THE ORIGIN OF DOLOMITE IN THE ASMARI FORMATION (OLIGOCENE-LOWER MIOCENE), DEZFUL EMBAYMENT, SW IRAN

Dolomitisation is an important factor controlling reservoir quality in the Asmari Formation in many producing fields in SW Iran. Dolostones have higher average porosities than limestones. Petrographic and geochemical studies have been used to determine the causes of Asmari dolomitisation at the Bibi Hakimeh and Marun fields and at the Khaviz anticline. The formation is generally characterized by a large‐scale trend of upward‐decreasing accommodation. Basal strata were deposited under relatively open‐marine, high‐energy conditions, whereas the Middle to Upper Asmari succession was deposited in relatively protected settings with more frequent evidence of exposure and evaporitic conditions. There is a general upward increase in the abundance of both anhydrite (occurring as nodules and cement) and dolomite. Two main types of dolomite fabric are recognised, reflecting the textures of the precursor limestones: (1) finely crystalline pervasive dolomite (commonly <20μ) replacing mud‐rich facies; and (2) combinations of finely crystalline replacive dolomite and surrounding areas of coarser dolomite cement (crystals up to 100μ) in grain‐supported facies. Fluid inclusion data indicate that finely crystalline dolomites formed at low temperatures (ca. <50°C), while the coarser dolomite formed at higher temperatures (50–;140°C). Whole rock‐carbonate oxygen and carbon isotope analyses of pure dolostone samples show no apparent correlation with either depositional or diagenetic textures: δ¹⁸O is generally 0 to 2.7‰ PDB, and δ¹³C is ?1 to 4‰ PDB. The importance of evaporated seawater to Asmari dolomitisation is indicated by the ubiquitous occurrence of felty‐textured anhydrite nodules in dolostone beds and the presence of high‐salinity fluid inclusions in dolomite. The derivation of dolomitising fluids from contemporaneous seawater is supported by the general correspondence between age estimates derived from the strontium isotope composition of anhydrites and dolomites and those derived from stratigraphic considerations. This suggested synsedimentary dolomitisation. Dolomitisation of the upper half of the Asmari Formation may have occurred as a result of two syn‐sedimentary mechanisms: (1) by the reflux of evaporative brines concentrated in shallow lagoons or sabkhas, through immediately underlying strata (mainly during highstands); and (2) by the flushing of platform‐top carbonates by basinal evaporated waters during lowstand/early transgression. Continued dolomitisation during deeper burial is supported by the presence of high‐temperature fluid inclusions and iron‐rich crystal rims. Dolomite within the lower part of the Asmari Formation probably mostly formed during burial as a result of compaction of, and fluid exclusion from, the underlying Pabdeh marls and shales.     

Investigating Geochemical Characterization of Asmari and Bangestan Reservoir Oils and the Source of H2S in the Marun Oilfield

Abstract

Geochemical evaluation is one of the most important and applicable methods for optimization of hydrocarbon exploration and production. In this article, the geochemistry of Asmari and Bangestan reservoir oils of Marun oil field was experimentally studied. Marun oil field is one of the giant oil fields in southwest Iran and has two oil reservoirs (Asmari and Bangestan) and one gas reservoir (Khami). The main goal of this study is to investigate the genetic behavior of the above oil reservoirs, focusing mainly on hydrogen sulfide pollutants. Biomarkers of saturated and aromatic fractions were studied on five polluted, three unpolluted Asmari, and two Bangestan reservoir oils. A triangular diagram was used to determine the chemical composition of the studied oil. The results show relatively higher oil maturity for both reservoirs with no biodegradation. The carbon preference index of both reservoir oils was also around 1, which indicates mature oil samples. The pristane-to-phytane ratio, Pri/nC₁₇ versus Phy/nC₁₈, terrigenous/aquatic ratio (TAR), and geochemical data all show that the source rock for both Asmari and Bangestan reservoirs is the same. This source rock was deposited in a reducing environment with algae (kerogen type II) organic matter and without any higher plants. Genetic potential studies of probable source rocks, by means of Rock-Eval VI analysis in Marun oilfield, present Kazhdomi and Garu as main source rocks. Biomarkers of sulfur compounds and structural analysis of Marun oil field revealed that hydrogen sulfide gas pollution in the Asmari reservoir originated from the Bangestan reservoir. In addition, thermal sulfate reduction was a possible main process for hydrogen sulfide formation.     

The effects of diagenesis on the petrophysical and geochemical attributes of the Asmari Formation,Marun oil field,southwest Iran

The distribution of good reservoir quality and its causes is the main challenges in carbonate reservoir characterization.This study investigates the effects of diagenetic processes on the reservoir quality of the carbonate successions of the Asmari Formation,in the Marun oil field,southwest Iran.The study applies an integrated approach including core petrography,petrophysical rock typing,stable carbon and oxygen isotopes as well as major and trace elements analyses.Petrographic studies and geochemical analyses express that the Asmari limestones have been affected mainly by compaction,dissolution,recrystallization,calcite and anhydrite cementation and dolomitization.Among those diagenetic overprints,dolomitization and dissolution played an important role to enhance the reservoir quality of the formation.Moreover,four types of dolomites were recognized and the rate of dolomitization increases toward the top of the Asmari carbonate successions.Possible models for dolomitization include mixing zone,brine reflux,seepage reflux and tidal pumping of seawater.Employing Flow Zone Index and Discrete Rock Type concepts led to classification of the Asmari reservoir into seven reservoir rock types.Integrating reservoir rock typing with petrographic studies and geochemical analyses also confirms that reservoir quality of the Asmari Fm.would have been mainly controlled by diagenetic processes.Moreover,stable isotopes,trace elements and facies analyses support the idea that carbonate intervals of the Asmari Formation were deposited in a warm,shallow-water environment under a saline condition.     

Estimating Total Organic Carbon Content and Source Rock Evaluation,Applying ΔlogR and Neural Network Methods: Ahwaz and Marun Oilfields,SW of Iran

Abstract

Well logging is a useful method for sedimentary basin and source rock evaluation. Source rocks have special responses in porosity and resistivity logs that can make them distinguishable from surrounding rocks. Therefore, well logging data and diagrams can be used as indicators of determination of source rock potential. Characterizations of Kazhdomi, Pabdeh, and Gurpi source rocks have been determined by geochemical analysis in some Iranian oilfields, but no total organic carbon (TOC) zonation and interpretation have been carried out in these formations yet. Several studies have confirmed the petroleum potential of the Kazhdomi formation in Dezful Embayment, but Pabdeh formation (more significant) and Gurpi (less significant) have been always the topics of Iranian petroleum geologist discussions in order to deermine whether these formations have the potential of generating oil and what the organic matter properties of these formations are. The purpose of this article is to calculate TOC values of the Pabdeh formation in Ahwaz and Marun oilfields using a combination of sonic and resistivity logs (ΔlogR method) and a neural network method. Then these TOC values were compared with TOC from geochemical analysis. Finally, the zonations of source rock in terms of TOC richness were carried out and TOC changes in the oilfields were shown by plotting Iso-TOC maps. It was found that due to the high local temperature gradient Pabdeh reaches an oil window level in some parts of Ahwaz and Marun oilfields. Hence, Pabdeh acts as a source rock for these two oilfields in some sections.     

DOLOMITIZATION AND RELATED FLUID EVOLUTION IN THE OLIGOCENE – MIOCENE ASMARI FORMATION, GACHSARAN AREA, SW IRAN: PETROGRAPHIC AND ISOTOPIC EVIDENCE

Petrographic and stable isotope investigations of Oligocene‐Miocene carbonates in the Asmari Formation from the Gachsaran oilfield and surrounding area in SW Iran indicate that the carbonates have been subjected to extensive diagenesis including calcite cementation and dolomitization. Diagenetic modification occurred in different diagenetic realms ranging from marine, meteoric and finally burial. Asmari carbonates were in general deposited in a ramp setting and are represented by intertidal to subtidal deposits together with lagoonal, shoal and low‐energy deposits formed below normal wave base. Lithofacies include bioclastic grainstones, ooidal and bioclastic, foraminiferal and intraclastic packstones, and mudstones. Multiple episodes of calcite cementation, dolomitization and fracturing have affected these rocks to varying degrees and control porosity. Four types of dolomites have been identified: microcrystalline matrix replacement dolomite (D1); fine to medium crystalline matrix replacement dolomite (D2); coarse crystalline saddle‐like dolomite cement (D3); and coarse crystalline zoned dolomite cement (D4). Microcrystalline dolomites (D1) (6–12 μm) replacing micrite, allochems and calcite cements in the mud‐supported facies prior to early compaction show δ¹⁸O and δ¹³C values of ?4.01 to +1.02‰ VPDB and ?0.30 to +4.08‰ VPDB, respectively. These values are slightly depleted with respect to postulated Oligocene‐Miocene marine carbonate values, suggesting their precipitation from seawater, partly altered by later fluids. The association of this type of dolomite with primary anhydrite in intertidal facies supports dolomitization by evaporative brines. Fine to medium crystalline matrix dolomites (D2) (20–60μm) occur mostly in grainstone facies and have relatively high porosities. These dolomites formed during early burial and could be considered as recrystallized forms of D1 dolomite. Their isotopic values overlap those of D1 dolomites, implying precipitation from similar early fluids, possibly altered by meteoric fluids. Coarse crystalline saddle‐like dolomites (D3) (200–300 μm) partially or completely occlude fractures and vugs. The vugs developed through the dissolution of carbonate components and rarely matrix carbonates, while fractures developed during Zagros folding in late Oligocene to early Miocene times. A final diagenetic episode is represented by the precipitation of coarse crystalline planar e‐s zoned dolomite (D4) (80–250 μm) that occurs in fractures and vugs and also replaces earlier dolomite and post‐dates stylolitization. Fluids responsible for the formation of D3 and D4 dolomites are affected by brine enrichment and increasing temperatures due to increasing burial. Reservoir porosity is dominated by microcrystalline pore spaces in muddy, dolomitized matrix and mouldic and vuggy porosity in grainstone. Porosity was significantly enhanced by the formation of multiple fracture systems.     

THE INFLUENCE OF TECTONICS ON THE ENTRAPMENT OF OIL IN THE DEZFUL EMBAYMENT, ZAGROS FOLDBELT, IRAN

The timing of the orogenic events associated with the closure of South Tethys significantly influenced the generation, migration and entrapment of petroleum in the Zagros Foldbelt of Iran. This influence was particularly important in the Dezful Embayment, which is one of the world's richest oil provinces, containing some 8% of global oil reserves in an area of only 60,000 sq. km. In the Dezful Embayment, oil and associated gas occur in two carbonate reservoirs ‐ the Sarvak Formation of Cenomanian to Turonian age, and the Oligocene ‐ Early Miocene Asmari Formation, sealed by the evaporites of the Gachsaran Formation. The oil and associated gas are trapped in large “whaleback” anticlines which formed during the Neogene Zagros orogeny. Two excellent source rocks, the Albian Kazhdumi Formation and the upper part of the Pabdeh Formation (Middle Eocene to Early Oligocene), supplied the Asmari and Sarvak reservoirs and with them form the Middle Cretaceous to Early Miocene Petroleum System. This system was found to be independent of older petroleum systems. Two particular problems are addressed in this paper. The first is the relative timing of trap formation versus oil expulsion from the source rocks. If oil expulsion occurred prior to Zagros folding, the oil would have migrated along gently dipping ramps towards the Persian (Arabian) Gulf and Southern Iraq, and would have been trapped a long way from the source kitchen. By contrast, if oil expulsion took place when the whaleback anticlines already existed or had at least begun to develop, the oil generated would have moved almost vertically towards the nearest anticline. Secondly, we assess the type of heatflow to be used for modelling. This could be either variable or constant, depending on the stability or instability of the Arabian Platform and on subsidence variations during source rock maturation. Our conclusions can be summarized as follows. First, the paroxysmal phase of Zagros folding commenced in the Dezful Embayment towards the end of the Middle Miocene around 10 Ma ago and continued throughout the Late Miocene and Pliocene. Second, bearing in mind the remarkable stability of the Arabian Platform for some 260 Ma, during which there was almost continuous gentle subsidence between the Permian transgression and the Early Miocene, a constant heatflow was used for modelling. Burial profiles and maturity indices, such as vitrinite reflectance and Rock‐Eval parameters, demonstrate that the Kazhdumi and Pabdeh source rocks reached the onset of oil expulsion during deposition of the Agha Jari Formation between 8 and 3Ma, depending upon the location. This chronology means that oil migrated from source rocks into preexisting Zagros structures. Therefore, oil migrated over short distances to nearby traps within well‐defined drainage areas, the geometry of which can be deduced from seismic data. Moreover, the Zagros folding induced prominent fracturing which can be observed both at outcrop and in wells. This fracturing, which affects lime‐stones as well as marls, enhanced subvertical migration of hydrocarbons towards the reservoirs. As a result of this short distance migration, oils can directly be linked to the source rocks which generated them by oil‐oil and oil‐source rock correlations based on stable isotope (σ¹³C, σ³⁴S) and biomarker data. Modelling of each drainage area provides estimates of the amount of oil expelled by each source rock. Calculated estimates can then be compared to the actual oil‐in‐place of the corresponding field. An example of this modeling procedure is given in this paper.     

BURIAL,TEMPERATURE AND MATURATION HISTORY OF CRETACEOUS SOURCE ROCKS IN THE NW PERSIAN GULF,OFFSHORE SW IRAN: 3D BASIN MODELLING

This study presents a 3D numerical model of a study area in the NW part of the Persian Gulf, offshore SW Iran. The purpose is to investigate the burial and thermal history of the region from the Cretaceous to the present day, and to investigate the location of hydrocarbon generating kitchens and the relative timing of hydrocarbon generation/migration versus trap formation. The study area covers about 20,000 km² and incorporates part of the intra‐shelf Garau‐Gotnia Basin and the adjacent Surmeh‐Hith carbonate platform. A conceptual model was developed based on the interpretation of 2700 km of 2D seismic lines, and depth and thickness maps were created tied to data from 20 wells. The thermal model was calibrated using bottom‐hole temperature and vitrinite reflectance data from ten wells, taking into account the main phases of erosion/non‐deposition and the variable temporal and spatial heat flow histories. Estimates of eroded thicknesses and the determination of heat‐flow values were performed by burial and thermal history reconstruction at various well and pseudo‐well locations. Burial, temperature and maturation histories are presented for four of these locations. Detailed modelling results for Neocomian and Albian source rock successions are provided for six locations in the intra‐shelf basin and the adjacent carbonate platform. Changes in sediment supply and depocentre migration through time were analyzed based on isopach maps representing four stratigraphic intervals between the Tithonian and the Recent. Backstripping at various locations indicates variable tectonic subsidence and emergence at different time periods. The modelling results suggest that the convergence between the Eurasian and Arabian Plates which resulted in the Zagros orogeny has significantly influenced the burial and thermal evolution of the region. Burial depths are greatest in the study area in the Binak Trough and Northern Depression. These depocentres host the main kitchen areas for hydrocarbon generation, and the organic‐rich Neocomian and Albian source rock successions have been buried sufficiently deeply to be thermally mature. Early oil window maturities for these successions were reached between the Late Cretaceous (90 Ma) and the early Miocene (18 Ma) at different locations, and hydrocarbon generation may continue at the present‐day.     

DEPOSITIONAL HISTORY AND SEQUENCE STRATIGRAPHY OF OUTCROPPING TERTIARY CARBONATES IN THE JAHRUM AND ASMARI FORMATIONS, SHIRAZ AREA (SW IRAN)

The Oligo-Miocene Asmari Formation is one of the most important petroleum reservoir units in the Zagros Basin of south and SW Iran. It mainly consists of limestones and dolomitic limestones with interbedded shales, together with a few intervals of sandstone and gypsum assigned to the Ahwaz and Kalhur Members, respectively. The Asmari Formation rests on the thin-bedded limestones of the Jahrum Formation (Paleocene-Eocene). In this paper, we report on the lithofacies characteristics of these two formations using data from three measured outcrop sections near Shiraz in SW Iran. From field and petrographic data, we have identified four major lithofacies and twelve subfacies which are interpreted to have been deposited in open-marine, shoal, lagoon and tidal flat settings.
We show that the Asmari and Jahrum Formations constitute two separate depositional sequences which are separated by a thin palaeosol, representing a type-one sequence boundary which can be correlated with global curves of relative sea-level. Each depositional sequence is composed of many metre-scale shallowing-upward parasequences. This is the first time that the Asmari and Jahrum Formations have been differentiated in the study area. We hope that this study will lead to a better understanding of the Asmari Formation in the subsurface in other parts of the Zagros Basin.     

鄂尔多斯盆地海相碳酸盐岩主要储层类型及其形成机制

对于鄂尔多斯盆地海相碳酸盐岩储层宏观分布规律和有利区带的认识目前尚不十分清楚，难以满足区带评价和目标优选的需求。为此，利用野外露头、钻井和地球物理测井资料并结合实验分析数据，深入探讨了该盆地海相碳酸盐岩储层的特征、形成机制和分布规律，并指出了下一步天然气勘探的方向。研究结果表明：①鄂尔多斯盆地海相碳酸盐岩主要发育岩溶型和颗粒滩型两类白云岩储层，前者发育于蒸发台地的含膏云岩和膏质云岩坪微相，主要分布在下奥陶统马家沟组马五段上组合及马一段和马三段，后者主要发育于台地边缘颗粒滩和台内颗粒滩微相，分布在中寒武统张夏组、上寒武统三山子组、马四段和马五段中组合；②颗粒滩型储层岩性为鲕粒云岩、砂屑云岩、晶粒云岩及微生物云岩，储集空间以残余粒间（溶）孔、微生物格架（溶）孔、晶间（溶）孔和溶洞为主，少量裂缝，孔隙度介于2.00%～18.03%，平均孔隙度为6.16%，机械沉积和微生物造丘是原生孔隙形成的重要机制，准同生溶蚀和裸露期风化壳岩溶作用是溶孔溶洞形成的主控因素，早期白云石化和封闭体系有利于孔隙的保持；③岩溶型储层岩性为（含）膏模孔细粉晶云岩和粉晶云岩，储集空间为膏模孔、溶洞及微裂缝，孔隙度介于2.00%～16.36%，平均孔隙度为5.98%，同生期层间岩溶和裸露期风化壳岩溶是膏模孔形成的主要机制，而膏模孔的保存受矿物充填和封闭体系两大因素的控制。结论认为，有利储层主要分布在该盆地鄂托克前旗—定边—上韩、桃利庙—吴起和榆林—志丹一带，其中桃利庙—吴起和榆林—志丹一带是深层碳酸盐岩气藏勘探最有利的区带。     

The Design of New Soft Sensors Based on PCA and a Neural Network for Parameters Estimation of a Petroleum Reservoir

Abstract

A new set of soft sensors is presented based on principal component analysis (PCA) and artificial neural network (ANN) methodologies for parameters estimation of a petroleum reservoir. The crude diagrams of reservoir parameters provide valuable evaluation for petrophysical parameters. These parameters, however, are usually difficult to measure due to limitations on cost reliability considerations, inappropriate instrument maintenance, and sensor failures. PCA is utilized to develop new soft sensors to incorporate reliability and prediction capabilities of ANN. For this purpose, a PCA model is derived to reconstruct a parameter from other reservoir parameters using their redundancy relations. The developed soft sensors are applied to reconstruct parameters of Marun reservoir located in Ahwaz, Iran, by utilizing the available geophysical well log data. The experimental results demonstrate that the proposed hybrid PCA-NN algorithm is able to reveal a better performance than the PCA and the conventional back propagation–based NNs.     

A NEW MODEL FOR THE FORMATION OF DOLOMITE IN THE TRIASSIC DOLOMITES,NORTHERN ITALY

The Pale di San Martino and Pale di San Lucano (referred to together as the “Pale”) are remnants of an originally more extensive carbonate platform in the Dolomite Mountains of northern Italy. The platforms are composed of Middle Triassic dolomites and limestones up to 1.6km thick. Limestones comprise 2–3% of the platform carbonates and are restricted to narrow corridors (tens to a few hundred metres wide, hundreds of metres long and high) within the dolomite. The mainly sucrosic dolomites of the Pale are interpreted as the result of recrystallization of a depositional, nearly stoichiometric Mg calcite under burial temperatures of ca. 40–70°C. The principal arguments are:

• The quantitative composition indicates that all platform carbonates are composed mainly of micritic crusts (45%; boundstone fabric prevails) and early cement (35%; microcrystalline, fibrous). The platform carbonates were probably mainly bacterial precipitates and tight at the sediment‐water interface (porosities <5%, permeabilities in the micro‐Darcy range).
• The limestone‐dolomite transitions (centimetres to decimetres wide) lack dolomite gradients. The lack of evidence for flowing fluids causing dolomitization suggests stagnant pore waters.
• The δ¹³C of average dolomite is 1.3‰ heavier than that of coeval limestone (666 analyses). The difference corresponds to a primary difference of 50mol% MgCO₃ and is interpreted as the result of fractionation. It suggests a dolomite precursor of very high Mg calcite, whereas present‐day limestone of the Pale was probably deposited as a basically Mg‐free polymorph (aragonite and/or calcite).
• The dolomite δ¹⁸O (+1 to ?11‰ VPDB) values show a scatter over the platform thickness and preserve randomly distributed values around 0‰. The scatter is probably due to selective re‐setting of δ¹⁸O near pore spaces and is mainly a sampling effect.
• The observation that ⁸⁷Sr/⁸⁶Sr ratios (77 analyses) of limestone and dolomite are either slightly higher or lower than Middle Triassic seawater, but almost never “normal marine”, suggests that the platform carbonates of the Pale were deposited from seawater contaminated with artesian freshwater. The limestone corridors are probably caused by artesian springs of somewhat higher than ambient depositional temperature, with low Mg calcite and/or aragonite deposited in or near fracture zones. The volumetrically subordinate cycle‐cap dolomite is possibly a primary precipitate.

     

CHEMOSTRATIGRAPHY OF CENOMANIAN–TURONIAN CARBONATES OF THE SARVAK FORMATION,SOUTHERN IRAN

Stable‐isotope and trace‐element analyses from five surface and subsurface sections of the mid‐Cretaceous Sarvak Formation in southern and offshore Iran confirm the presence of the regional‐scale Turonian unconformity and of a more local Cenomanian–Turonian unconformity. The geochemical results indicate the presence of previously unrecognized and/or undifferentiated subaerial exposure surfaces. Sarvak Formation carbonates at or near palaeo‐exposure surfaces show varying degrees of diagenetic modification, and more extensive alteration is associated with longer periods of exposure. The subaerial exposure and associated diagenetic processes greatly influenced reservoir quality and amplified karstification and evolution of porosity in the Upper Sarvak Formation. The palaeo‐exposure surfaces are identified by their negative δ¹³C values (as low as – 6.4%) and negative δ¹⁸O values (as low as –9.4%), together with low Sr concentrations and relatively high ⁸⁷Sr/⁸⁶Sr ratios. These geochemical characteristics are interpreted to be the result of the interaction of the Sarvak Formation carbonates with meteoric waters charged with atmospheric CO₂. The meteoric waters also caused karstification and soil formation which in some places extends a few metres below the exposure surfaces. Depleted carbon values were not recorded in areas where palaeosols are not well developed or where the uppermost layers of the Sarvak Formation have been removed by erosion.     

伊拉克A油田Asmari组混积型碳酸盐岩储层隔夹层研究

伊拉克A油田Asmari组为大型混积型碳酸盐岩油藏,发育灰岩、白云岩、砂岩、泥岩和硬石膏等多种岩性,储层复杂、非均质性强,存在多种类型的隔夹层。基于岩心、薄片、测井和分析测试等资料,对研究区隔夹层类型及特征展开综合分析,识别出了泥岩、硬膏岩和泥-微晶碳酸盐岩3类隔夹层。泥岩和硬石膏致密无孔隙、基本不具有渗流能力,对流体流动可以起到阻挡作用;泥-微晶碳酸盐岩属于细粒碳酸盐岩沉积,孔隙度低,但一般裂缝较发育,具有一定渗流能力,不能对流体起到有效的隔挡作用。硬石膏主要在油田中部及北部A段发育,其对油田北部储层纵向连通起到一定隔挡作用,导致纵向压力衰竭不一致。泥岩主要在C段顶部、B4和B1层发育,平面上主要在油田南部较发育。C段顶部发育一套厚度较大、稳定分布的泥岩隔层,将C段和上部B段及A段分隔为两个独立的油水系统,并有效阻挡了C段水层锥进到B段;B4和B1层泥岩较发育,但由于油田南部区域断层和裂缝较发育,导致泥岩隔夹层未能起到有效隔挡作用。搞清研究区隔夹层类型、分布及是否起隔挡作用,对A油田各区域各小层有效动用开发、见水规律研究具有很好的指导意义。     

CARBONATE RESERVOIR ROCKS AT GIANT OIL AND GAS FIELDS IN SW IRAN AND THE ADJACENT OFFSHORE: A REVIEW OF STRATIGRAPHIC OCCURRENCE AND PORO‐PERM CHARACTERISTICS

SW Iran and the adjacent offshore are prolific petroleum‐producing areas with very large proven oil and gas reserves and the potential for significant new discoveries. Most of the oil and gas so far discovered is present in carbonate reservoir rocks in the Dehram, Khami and Bangestan Groups and the Asmari Formation, with smaller volumes in the Dashtak, Neyriz, Najmeh, Gurpi, Pabdeh, Jahrum, Shahbazan, Razak and Mishan (Guri Member) Formations. The Permo‐Triassic Dehram Group carbonates produce non‐associated gas and condensate in Fars Province and the nearby offshore. The Jurassic – Lower Cretaceous Khami Group carbonates are an important producing reservoir at a number of offshore fields and in the southern Dezful Embayment, and are prospective for future exploration. Much of Iran's crude oil is produced from the Oligo‐Miocene Asmari Formation and the mid‐Cretaceous Sarvak Formation of the Bangestan Group in the Dezful Embayment. This review paper is based on data from 115 reservoir units at 60 oil‐ and gasfields in SW Iran and the adjacent offshore. It demonstrates that the main carbonate reservoir units vary from one‐another significantly, depending on the particular sedimentary and diagenetic history. Ooidal‐grainstones and rudist‐ and Lithocodium‐bearing carbonate facies form the most important reservoir facies, and producing units are commonly dolomitised, karstified and fractured. In general, reservoir rocks in the study area can be classified into six major types: grainstones; reefal carbonates; karstified, dolomitised and fractured carbonates; and sandstones. The stratigraphic distribution of these reservoir rocks was principally controlled by the palaeoclimatic conditions existing at the time of deposition. A comparative reservoir analysis based on core data shows that dolomitised and/or fractured, grain‐dominated carbonates in the Dehram Group, Lower Khami Group and Asmari Formation typically have better reservoir qualities than the Cretaceous limestones in the Upper Khami and Bangestan Groups.     

BURIAL HISTORY RECONSTRUCTION USING LATE DIAGENETIC PRODUCTS IN THE EARLY PERMIAN SILICICLASTICS OF THE FARAGHAN FORMATION, SOUTHERN ZAGROS, IRAN

In spite of the increasing importance to hydrocarbon exploration and production of the Palaeozoic succession in the Zagros area of SW Iran, few burial history and palaeothermal modelling studies of the interval have been carried out. This paper attempts to assess the burial and palaeotemperature history of the Lower Permian Faraghan Formation which is composed of stromatolitic dolomites overlain by mainly cross‐bedded sandstones. The formation grades up into the thick bedded carbonates of the Upper Permian Dalan Formation. The Faraghan and Dalan Formations are major hydrocarbon reservoir units in SW Iran and are time‐equivalents of the Unayzah and Khuff Formations in Saudi Arabia, respectively. The Faraghan Formation consists of shallow‐marine siliciclastics and foreshore deposits, including tidal‐flat and tidal‐channel, estuarine, sabkha, shoreface and offshore facies. In this study, diagenetic constituents are used to evaluate the formation's burial history in the Southern Zagros, an area for which only limited subsurface data is available. A burial history diagram for the formation was constructed for well Finu # 1 using WinBury^TM software. The diagram shows that the formation underwent progressive burial at variable rates between its deposition and the mid‐Tertiary, since when it has undergone rapid uplift. Burial diagenetic products in the Faraghan Formation comprise saddle, ferroan and zoned dolomites, together with dickite, illite/sericite and chlorite minerals. Additional burial‐related features include stylolites and dissolution seams. Isotopic signatures (δ¹⁸O versus δ¹³C) of the ferroan dolomites suggest a burial trend for the formation. Reconstruction of the paragenetic sequence together with the burial history diagram suggests a maximum burial depth of about 5000 m and a wide palaeotemperature range of 80‐160°C. However considering the saddle dolomites as a palaeothermometer, the temperature range narrows to 78 to 138 °C. The burial depth and temperature ranges closely correlate with the main stage of oil generation to the dry gas zone.     

PREDICTION OF OPEN FRACTURES IN THE ASMARI FORMATION USING GEOMETRICAL ANALYSIS: AGHAJARI ANTICLINE,DEZFUL EMBAYMENT,SW IRAN

Reservoir quality in the carbonates of the late Oligocene – early Miocene Asmari Formation at oilfields in SW Iran is enhanced by the presence of a well‐developed fracture network. In anticlinal structures, fracture density is partly controlled by geometrical parameters such as the fold curvature. In this study, a geometrical analysis of the Asmari Formation at the NW‐SE oriented Aghajari Anticline in the Dezful Embayment is presented, and is based on inscribed circle and curvature analyses of the fold. Iso‐curvature and fracture potential maps of the Asmari Formation based on the geometrical analysis are compared to the results of fracture density logs determined from image logs at four widely‐spaced wells, and to dynamic mud loss data. The geometrical analysis demonstrates that in areas of high curvature (such as the SE and NW parts of the SW limb of the Aghajari Anticline and the central part of the NE limb), the fracture density is high. Regions of high curvature (in plan or section view) have the greatest potential to develop open fractures. The predicted fracture density distribution based on the geometrical analysis of the Asmari Formation is in good agreement with actual fracture data from the four wells and with mud loss data from the Aghajari oilfield.     

BURIAL AND MATURATION HISTORY OF THE HEGLIG FIELD AREA, MUGLAD BASIN, SUDAN

The NW‐SE trending Muglad Basin (SW Sudan) is one of a number of Mesozoic basins which together make up the Central African Rift System. Three phases of rifting occurred during the Cretaceous and Tertiary, resulting in the deposition of at least 13 km of sediments in this basin. Commercial hydrocarbons are sourced from the Barremian‐Neocomian Sharaf Formation and the Aptian‐Albian Abu Gabra Formation. The Heglig field is located on a NW‐SE oriented structural high in the SE of the Muglad Basin, and is the second‐largest commercial oil discovery in Sudan. The high is characterised by the presence of rotated fault blocks, and is surrounded by sub‐basinal structural lows. We modelled the geohistories of three wells on different fault blocks in the Heglig field (Heglig‐2, Barki‐1 and Kanga‐1) and one well in the Kaikang Trough (May25–1). The models were calibrated to measured porosity‐depth data, temperature and vitrinite reflectance measurements. Predicted present‐day heat flow over this part of the Muglad Basin is about 55 mW/m². However, a constant heat‐flow model with this value did not result in a good fit between calculated vitrinite Ro and measured Ro at the wells studied. Therefore a variable heat‐flow model was used; heat flow peaks of 75, 70 and 70 mW/m² were modelled, these maxima corresponding to the three synrift phases. This model resulted in a better fit between calculated and measured Ro. The source rock section in the Sharaf and Abu Gabra Formations was modelled for hydrocarbon generation in the four wells. Model results indicate that the present‐day oil generation window in the Hegligfield area lies at depths of between 2 and 4 km, and that oil and gas generation from the basal unit of the Abu Gabra Formation occurred between about 90 and 55 Ma and from the Sharaf Formation between 120 and 50 Ma. The results suggest that the oils discovered in the Heglig area have been generated from a deep, mature as‐yet unpenetrated source‐rock section, and/or from source rocks in nearby sub‐ basinal areas.     

鄂尔多斯盆地乌审旗隆起东北侧怀远运动不整合特征及其对岩溶储层形成的意义

怀远运动（加里东期Ⅰ-Ⅱ幕）是鄂尔多斯盆地早古生代一次较大的构造活动,其影响仅次于加里东期（Ⅲ幕）—海西运动,存在长时间的沉积间断,在古隆起附近形成了较为有利的岩溶储层。怀远运动不整合面在乌审旗隆起东北侧表现为奥陶系马家沟组一段与寒武系三山子组之间的平行不整合接触。不整合面上、下均为碳酸盐岩地层,但在测井电性、岩石矿物、元素以及同位素分析上都存在很大的差异。三山子组为细晶白云岩,在测井响应上具有低伽马值、高电阻率的特征,发育不规则状溶蚀孔隙,是岩溶储层发育段。三山子组储层多属于相对高能的近隆浅滩、正常海水环境,白云化作用为浅埋藏期渗透回流白云岩化。马家沟组一段是怀远运动后的首套沉积地层,由于靠近乌审旗古陆,岩性复杂,呈现出膏-云-泥-砂混杂沉积的特征,沉积时虽然也属于海相环境,但其与三山子组沉积时相比已发生了较大变化,属于海侵早期靠近古陆的混积潮坪沉积环境,气候相对干旱,以海源碳酸盐沉积为主,又常有间歇性的陆源碎屑补给,白云岩则是准同生期萨布哈白云岩化作用的产物。三山子组储层受相对高能原始相带以及怀远运动相关白云岩化作用和岩溶作用共同控制,储层多为白云岩化作用和表生岩溶作用叠加形成,分...     

A FUZZY LOGIC APPROACH TO ESTIMATING HYDRAULIC FLOW UNITS FROM WELL LOG DATA: A CASE STUDY FROM THE AHWAZ OILFIELD, SOUTH IRAN

Porosity-permeability relationships in the framework of hydraulic flow units can be used to characterize heterogeneous reservoir rocks. Porosity is a volumetric parameter whereas permeability is a measure of a rock's flow properties and depends on pore distribution and connectivity. Thus zonation of a reservoir using flow zone indicators and the identification of flow units can be used to evaluate reservoir quality based on porosity-permeability relationships.
In the present study, we attempt to make a quantitative correlation between flow units and well log responses using fuzzy logic in the mixed carbonate-clastic Asmari Formation at the Ahwaz oilfield, South Iran. A hybrid neuro-fuzzy approach was used to verify the results of fuzzy modelling. For this purpose, well log and core data from three wells at Ahwaz were used to make an intelligent formulation between core-derived flow units and well log responses. Data from a separate well was used for evaluation and validation of the results.
The results of this study demonstrate that there is a good agreement between core-derived and fuzzy-logic derived flow units. Fuzzy logic was successful in modelling flow units from well logs at well locations for which no core data was available.     

IMPACT OF DIAGENESIS ON RESERVOIR QUALITY IN RAMP CARBONATES: GIALO FORMATION (MIDDLE EOCENE), SIRT BASIN,LIBYA

The reservoir quality of Middle Eocene carbonates in the intracratonic Sirt Basin is strongly influenced by depositional facies and various diagenetic processes. Based on data from core samples and well logs from five boreholes in the Assumood and Sahl gasfields in the subsurface of the north‐central Sirt Basin, six major carbonate facies (and fourteen microfacies) are distinguished in the Middle Eocene Gialo Formation (thickness ～1100 ft/335 m). Wackestones‐packstones dominate the Gialo Formation with abundant grains of larger benthic foraminifera, especially nummulites, in a matrix composed mostly of finely comminuted bioclastic material. Sediments were deposited as a mosaic of facies on a broad carbonate ramp in moderate‐energy nummulite‐packstone banks, with locally restricted back‐bank lagoons and fore‐bank areas of foraminiferal debris passing to offshore lime mudstones. Marine diagenesis was minor with micritization of bioclasts and rare vadose marine fibrous cements. Sparry calcite cements are ubiquitous and were precipitated during shallow to moderate burial from seawater and/or meteoric water, the latter largely unaffected by surface‐pedogenic processes. This is indicated by the fabrics and pre‐ and post‐compaction precipitation of drusy spar and echinoderm overgrowths, and supported by their bright‐to‐dull luminescence and low negative δ¹⁸O signatures (‐2.68 to ‐4.16%° PDB). Some early neomorphic alteration of calcitic bioclasts is suggested by bright CL and marine to low negative δ¹⁸O values (‐1.06 to –3.93%° PDB). Bioclastic grains have δ¹³C values ranging between 0.76 and 1.19%° PDB, interpreted as marine signatures. Similar low positive δ¹³C values of the cements (0.9 to 1.05 %°) indicate a source of carbonate from dissolution of grains and/or seawater/meteoric water, but without any near‐surface/soil effects. Dissolution of grains and matrix, notably originally aragonitic grains but also the originally high‐Mg calcite nummulites, was a major porosity‐enhancing process, and took place from shallow to moderate burial depths. Fractures may locally have increased porosity too. Shallow‐water packstones/rudstones containing both primary intergranular and secondary biomouldic porosity have the best reservoir quality and these are concentrated in the upper parts (top ～100 ft/30 m) of the wells, with porosity‐permeability decreasing downwards. This trend relates to the broad, large‐scale facies pattern of more mud‐dominated facies giving way upwards to more grainy, nummulite‐dominated facies as a result of an overall shallowing of the depositional environment. In addition, the influx of meteoric waters in the upper part of the Gialo platform, before drowning and deposition of the overlying Augila Shale, increased porosity through dissolution. This integrated study has helped in understanding the reservoir heterogeneity and hydrocarbon potential of the Gialo carbonates.