Origin and Potential of Unconventional Jurassic oil reservoirs on the northern 
Arabian Plate

Goff, J.

doi:10.2523/93505-ms

Cited by 3 publications

(1 citation statement)

References 5 publications

(8 reference statements)

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“…Uppermost Triassic anhydrites and shales may act as regional seals. The Jurassic petroleum system based on Middle to Upper Jurassic source rocks (Sargelu and Naokelekan Formations) deposited in the Gotnia Basin (Goff, 2005), and the Cretaceous petroleum system based on (Tithonian to) Lower Cretaceous source rocks (Chia Gara / Sulaiy / Makhul Formations), are the most important systems in Iraq (Aqrawi and Badics, 2015). Thick anhydrites of the Gotnia Formation represent a potential seal for the Jurassic petroleum system.…”

Section: Geological Settingmentioning

confidence: 99%

Source‐rock Maturity, Hydrocarbon Potential and Oil – Source‐rock Correlation in Well Shorish‐1, Erbil Province, Kurdistan Region, Iraq

Sachsenhofer

Bechtel

Gratzer

et al. 2015

Journal of Petroleum Geology

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The Shorish-1 exploration well is located in Erbil Province in the Kurdistan region of Iraq, on the outskirts of Erbil City near the dividing line between the Low Folded and High Folded Zones of the Zagros foldbelt. The well penetrated rocks which are between Miocene and Late Triassic in age. The depositional environment, source potential and maturity of organicrich intervals within the well succession were investigated using 38 cuttings samples. All samples were analysed for bulk geochemical parameters (i.e. total organic carbon, total carbon, sulphur, Rock-Eval). A subset of 13 samples was selected for biomarker analysis, pyrolysis -gas chromatography and isotope investigations. In addition non-commercial oil and oil impregnations were investigated for oil-source correlations.Source rocks occur in the Jurassic Sargelu and Naokelekan Formations and the lowermost Cretaceous Chia Gara Formation. Analytical results suggest that these source rocks were deposited in a carbonate-rich, anoxic environment in an intrashelf basin setting with free H 2 S in the water column. Oxygen-depleted conditions were favoured by salinity stratification. The average preserved TOC contents of the 100 m thick Sargelu Formation and the 25 m thick Naokelekan Formation are 2.2 % and 4.6 %, respectively. The TOC content of the Chia Gara Formation decreases upwards and averages 3.2 % within its lower 40 m. Very high sulphur contents suggest the presence of kerogen Type II-S, and that all the formations have generated sulphur-rich hydrocarbons at relatively low maturities.In contrast to the oil impregnations within Jurassic strata, the oil and the oil impregnations within Cretaceous rocks are heavily biodegraded. Oil biomarker and isotope data indicate generation from the above-mentioned Jurassic and Cretaceous source rock formations. As a result, generation from Triassic and Paleogene rocks can be excluded or is of negligible significance.Numerical models show that hydrocarbon generation rates from the Sargelu, Naokelekan and Chia Gara Formations peaked firstly at about 55 Ma (Paleocene/Eocene) and then again at 5 Ma before present (late Miocene/Pliocene). The first peak resulted from increased Paleocene subsidence, and the second peak was related to deep late Miocene/Pliocene burial. Hydrocarbon generation ceased during Recent uplift, during which ~2000 m of the Late Neogene succession was eroded.

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Section: Geological Settingmentioning

confidence: 99%

Source‐rock Maturity, Hydrocarbon Potential and Oil – Source‐rock Correlation in Well Shorish‐1, Erbil Province, Kurdistan Region, Iraq

Sachsenhofer

Bechtel

Gratzer

et al. 2015

Journal of Petroleum Geology

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Fracture Acidizing of a HTHP Exploratory Well in Deep Carbonate Reservoir: A Case Study

Al-Omair

Siddiqui

Singh

et al. 2008

Europec/Eage Conference and Exhibition

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The Jurassic carbonate reservoirs in Kuwait are deep, characterized with extremely low porosity and permeability. The temperature of these reservoirs ranges between 250–300ºF. High production from these types of reservoirs will be possible if the oil filled fractures can discharge into large connected fractures during drawdown. Hence, these reservoirs are well sited for fracture stimulation to be exploited properly. Fracture acidization of a deep HTHP exploratory well producing from limestone reservoir was performed successfully without any operational problem. The well was drilled to a depth of above 16,000 ft using high density oil-based mud (OBM). The well was tested in three intervals out of which the middle section produced high API gravity oil with gas. Initially, the well flowed at low rates but little increase in production was observed after matrix stimulation with emulsified acid. Lack of flow channels in the matrix was indicated by the continuous increase in bottomhole pressure during long shut-in period with a consistent drawdown pressure of 8,000 psi. The low production of the well was investigated using borehole image logs, mud logs, daily drilling reports and core examination study. The findings of the study combined with data of the offset wells prompted fracture acidizing treatment. The well was fracture acidized using emulsified acid due to which the oil and gas production increased by several folds. Prior to the main fracturing treatment a step rate test, using 2 wt% KCl brine with surfactant, was conducted to determine reservoir parameters such as fracture extension pressure, fracture closure pressure and instantaneous shut-in pressure. The paper highlights the usefulness of old data in deciding and designing the fracturing treatment to enhance reservoir deliverability. Additionally, a procedural mechanism for the selection of stimulation techniques, acid or proppant, in deep limestone reservoirs is discussed in this paper. Introduction Massive exploratory activities are in progress in Jurassic carbonate formations in north Kuwait at a depth of above 16,000 ft. Drilling in deep reservoirs has always been a challenge with operational considerations. If the reservoir quality is low the challenge will be compounded with the uncertainty of flow of reservoir fluids to surface. Drilling in deep reservoirs necessitates the use of high density muds. Usually, when mud densities go high, the choices of least damaging drill-in fluids will become narrow. Achieving high mud densities without increasing solid content will be almost impossible unless high cost clear brines are used. The use of high cost formate or halide brines in fractured reservoirs will be a concern due to the risk of potential losses of these brines into the formation. In such scenarios drilling fluids with barite as a weighting material are typically used to maintain the required density to control downhole pressures. Some other weighting materials, heavier than barite, such as manganese tetroxide and ilmenite are also reported to be used in high density drilling fluids (Nicora et al. 2001). Drilling fluids exert great influence on well productivity in terms of induced formation damage (Goode and Stacy 1984). For drilling the pay/target zone, selection of appropriate drilling fluid is most important and this becomes highly significant in HTHP drilling and completion (Svela and Wennberg 2006). Drilling in HTHP environment with increased depths at temperatures above 250oF poses several challenges on the selection of mud type. Normal water-based muds (WBM) and OBM or emulsion muds cannot be simply used in these applications as the stability of fluid loss control polymers and other ingredients will be at stake, wheras the increased quantity of barite potentially leads to sagging.

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Integrated Geo-Statistical Modeling – An Effective Tool to Meet the Exploration Challenge of Low Porosity Carbonate Reservoir within Najmah-Sargelu Formation, Kuwait

Nath

Prasad

Khan

et al. 2011

SPE EUROPEC/EAGE Annual Conference and Exhibition

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The emergence of low porosity carbonate lithofacies of Najmah-Sargelu Formation as a commercial hydrocarbon play has led to change the exploration perspective of these formations. Several wells from different structures in Kuwait has shown the production potential of light oil@ 1000–4000 BOPD and natural gas 3.8–19.0 MMSCFD. The production has been obtained from bituminous mudstone, wackestone and algal limestone from Najmah-Sargelu Formation. Understanding the geometry and distribution of carbonate lithofacies of Najmah-Sargelu Formation is a major exploration challenge. Geo-statistical 3D model is a dynamic tool, which has been utilized to quantify the geometry and spatial distribution of carbonate lithofacies vis-a-vis its continuity. A careful geo-statistical workflow was evolved to address the major challenges of these reservoirs. An artificial intelligence, neural network was trained against cored section and subsequently applied in the noncored sections for lithofacies prediction. Sequence Stratigraphic framework, seismic grid and 3D geo-statistical modeling were integrated to create a geological model. Core-measured rock property data were analyzed to illustrate the distributions of core porosity and permeability of Najmah-Sargelu lithofacies. The distribution of internal properties and heterogeneity has been quantitatively described as the relationship of a reservoir facies within a sequence stratigraphic framework. Spatial estimation of lithofacies and reservoir properties provides insight into the deposition and diagenetic process of the reservoir units. The depositional pattern and connectivity analysis suggests a ramp setting in inner shelf environment of deposition with three major alternate transgressive and regressive sequences. An integrated geo-statistical modeling has resulted in depicting the internal geometry and connectivity of low porosity carbonate lithofacies thereby reducing the uncertainty in volumetric assessment in the delineation phase of Najmah-Sargelu Formation.

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Origin and Potential of Unconventional Jurassic oil reservoirs on the northern Arabian Plate

Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract

Cited by 3 publications

References 5 publications

Source‐rock Maturity, Hydrocarbon Potential and Oil – Source‐rock Correlation in Well Shorish‐1, Erbil Province, Kurdistan Region, Iraq

Source‐rock Maturity, Hydrocarbon Potential and Oil – Source‐rock Correlation in Well Shorish‐1, Erbil Province, Kurdistan Region, Iraq

Fracture Acidizing of a HTHP Exploratory Well in Deep Carbonate Reservoir: A Case Study

Integrated Geo-Statistical Modeling – An Effective Tool to Meet the Exploration Challenge of Low Porosity Carbonate Reservoir within Najmah-Sargelu Formation, Kuwait

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