ADDRESSING RESERVOIR HETEROGENEITY BY INTEGRATION OF GEOCHEMISTRY AND PETROPHYSICAL LOGS IN CARBONATE PROSPECTS

2021 ◽  
Author(s):  
Kemal C. Hekimoglu ◽  
◽  
Filippo Casali ◽  
Antonio Bonetti ◽  
◽  
...  
Keyword(s):  
Focal Point ◽  
Source Rocks ◽  
Geochemical Data ◽  
Reservoir Properties ◽  
Formation Evaluation ◽  
Geomechanical Properties ◽  
Reservoir Rocks ◽  
Production Allocation ◽  
Petrophysical Logs ◽  
Geochemical Analyses

Formation evaluation challenges in highly fractured, stacked reservoirs with multiple source rocks and structural complexities that have complicated charging histories are common in the Middle East. Finding additional pay zones, understanding the contribution of individual oils to the overall production, or evaluating the compartmentalization within the reservoir by resolving the heterogeneity of the reservoir rocks are to name but a few. This work tries to understand the challenges posed by the subsurface complexities and attempts to find answers through physical evidence, using both onsite data acquired during drilling and data gathered through organic and inorganic laboratory measurements. Formation evaluation challenges are mostly attributed to formation heterogeneity, which we have aimed to address through the integration of petrophysical and geochemical data within this work. This project encompasses the integration of petrophysical and geochemical analyses of the reservoir rocks. Geochemical data have provided the ability to make maturity, richness, and other character interpretations and will be combined with important petrophysical properties of the carbonate intervals to predict reservoir heterogeneities. These interpretations could support perforation interval selection on subsequent wells in the field through the understanding of the mobility of the oils and, ultimately, production allocation. Best practices for thermally extracting hydrocarbons from drill cuttings, quality-controlling advanced mud gas data, and interpretive processes together with the entire workflow followed will also be elaborated. The analysis has the objectives of establishing results to support completion decisions through understanding reservoir quality, reservoir fluid communication, and compartmentalization specific to the basin studied. The petrophysical reservoir properties such as hydrocarbons in place, mobility of the oils, porosity, permeability, fracture intensity, geomechanical properties (brittle vs. ductile), and production allocation will be tied in to geochemical analyses to this extent. The focal point of the work is ascertaining and characterizing both the reservoir properties using a number of integrated analytical techniques on DST oil samples of 12 offset wells and rock cuttings, as well as petrophysical logs and advanced mud gas data. The concepts, tools, and methods that have been demonstrated for evaluating crude oils, natural gases, and petrophysical characteristics of the rocks are applicable to many problems in petroleum production and field development as well as exploration efforts.

Shale gas resource assessment in the Merlinleigh Sub-basin, Carnarvon Basin

2015 ◽  
Vol 55 (2) ◽  
pp. 452
Author(s):  
Joanna Wong ◽  
Mohammad Bahar
Keyword(s):  
Shale Gas ◽  
Resource Assessment ◽  
Poor Quality ◽  
Organic Content ◽  
Source Rocks ◽  
Geochemical Data ◽  
Geochemical Parameters ◽  
The Monte Carlo Method ◽  
Petrophysical Logs ◽  
Carnarvon Basin

The recent shale gas developments in the US have encouraged exploration for shale gas resource in WA. In the largely unexplored Carnarvon Basin, the Merlinleigh Sub-basin is predominately of Permian strata and has been shown to contain high-quality gas-prone source rocks from geochemical data. Three main potential shale layers, the Gneudna Formation, Wooramel Group and the Byro Group, were identified based on the shale ranking parameters. Geochemical data was collected and analysed for the type of kerogen, total organic content (TOC), generation potential and thermal maturity. These parameters enabled a gas-in-place resource estimation to be made for each of the formations. The TOC data from various wells were validated by using petrophysical logs and the ΔlogR method. In comparison with the geochemical data, both values produced a good match, validating both sets of data. The three layers were ranked according to their geochemical parameters and any petrophysical or geomechanical characteristics. It was identified that the Wooramel Group contains the best quality source rocks, followed by the Byro Group. The Gneudna Formation was found to have poor quality source rocks. The Monte Carlo method by Crystal Ball was selected to estimate the probabilistic resources of these three layers. According to the P50 estimations, the Byro Group, Wooramel Group and the Gneudna Formation contained resources of 51.6 tcf, 40.1 tcf and 1.4 tcf, respectively.

Shale gas resource assessment in the Merlinleigh Sub-basin, Carnarvon Basin

2015 ◽  
Vol 55 (2) ◽  
pp. 471
Author(s):  
Joanna Wong ◽  
Mohammad Bahar
Keyword(s):  
Shale Gas ◽  
Resource Assessment ◽  
Poor Quality ◽  
Organic Content ◽  
Source Rocks ◽  
Geochemical Data ◽  
Geochemical Parameters ◽  
The Monte Carlo Method ◽  
Petrophysical Logs ◽  
Carnarvon Basin

The recent shale gas developments in the US have encouraged exploration for shale gas resource in WA. In the largely unexplored Carnarvon Basin, the Merlinleigh Sub-basin is predominately of Permian strata and has been shown to contain high-quality gas-prone source rocks from geochemical data. Three main potential shale layers, the Gneudna Formation, Wooramel Group and the Byro Group, were identified based on the shale ranking parameters. Geochemical data was collected and analysed for the type of kerogen, total organic content (TOC), generation potential and thermal maturity. These parameters enabled a gas-in-place resource estimation to be made for each of the formations. The TOC data from various wells were validated by using petrophysical logs and the ΔlogR method. In comparison with the geochemical data, both values produced a good match, validating both sets of data. The three layers were ranked according to their geochemical parameters and any petrophysical or geomechanical characteristics. It was identified that the Wooramel Group contains the best quality source rocks, followed by the Byro Group. The Gneudna Formation was found to have poor quality source rocks. The Monte Carlo method by Crystal Ball was selected to estimate the probabilistic resources of these three layers. According to the P50 estimations, the Byro Group, Wooramel Group and the Gneudna Formation contained resources of 51.6 tcf, 40.1 tcf and 1.4 tcf, respectively.

scholarly journals Production Allocation: Rosetta Stone or Red Herring? Best Practices for Understanding Produced Oils in Resource Plays

Minerals ◽  
2020 ◽  
Vol 10 (12) ◽  
pp. 1105
Author(s):  
Craig D. Barrie ◽  
Catherine M. Donohue ◽  
J. Alex Zumberge ◽  
John E. Zumberge
Keyword(s):  
Case Studies ◽  
Time Lapse ◽  
Source Rocks ◽  
Individual Development ◽  
Geochemical Data ◽  
Total Output ◽  
Production Allocation ◽  
The Usa ◽  
Rock Characterization ◽  
End Members

The production of crude oil from resource plays has increased enormously over the past decade. In the USA, around 63% of total output in 2019 was from unconventional production. The major unconventional plays in the USA (e.g., Permian Basin, Anadarko Basin, Eagle Ford, etc.) have become some of the world’s largest oil producers. However, unlike “conventional” exploitation, the target zones in unconventional systems are generally the source rocks themselves or adjacent strata and require numerous horizontal wells and stimulation via hydraulic fracturing to meet production targets. In order to maximize production, operators have developed various well stacking methods, all of which require some form of monitoring to ensure that well spacing is optimized and fluid production is not being “stolen” from adjacent formations, thereby reducing the production potential in associated wells. This necessity, amongst other geochemical considerations related to source rock characterization, has resulted in the expansion of “production allocation” and “time lapse geochemistry” methods. These methods were initially developed for conventional production decades ago, but have since been adapted to unconventional systems. However, the direct applicability of this method is not straightforward and numerous considerations need to be taken into account, foremost among which are: (1) “What defines your end-members?” (2) “Are these end-members valid across a meaningful development area?” and (3) “What is the most appropriate use of geochemistry data in these systems?”. Reservoir geochemistry studies, which include both “time lapse geochemistry/production monitoring” and “production allocation”, are valuable geochemical methods in unconventional plays but need to be used appropriately to provide the cost savings and business direction that operators expect. In this paper, we will discuss a number of case studies, both theoretical and natural, and outline the important factors which need to be considered when designing a reservoir geochemistry study and the common pitfalls which exist. The case studies and best practice approach discussed are designed to highlight the power and flexibility of geochemical data collection methods, integration with the operator’s knowledgebase, and other analytical methods to customize the program for individual development programs. Emphasis is placed upon developing robust and applicable fluid relationships from geochemical data and evidence for statistically significant changes through time.

Assessing source rock distribution in Heather and Draupne Formations of the Norwegian North Sea: A workflow using organic geochemical, petrophysical, and seismic character

2015 ◽  
Vol 3 (3) ◽  
pp. SV45-SV68 ◽  
Author(s):  
Balazs Badics ◽  
Anthony Avu ◽  
Sean Mackie
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Seismic Data ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Geochemical Data ◽  
Seismic Attribute ◽  
Attribute Analysis ◽  
Seismic Characterization ◽  
Petrophysical Logs

The organic-rich upper Jurassic Draupne and Heather Formations are the main proven source rocks of the Norwegian North Sea. We have developed a workflow for the organic geochemical, petrophysical, and seismic characterization of the Draupne and Heather Formation source rocks in a [Formula: see text] study area in quadrant 25 in the Viking Graben in the Norwegian North Sea. We characterized the vertical and lateral organic richness variations using biostratigraphy, organic geochemical data, and petrophysical logs. The Draupne Formation is a rich (6.5 wt.% total organic carbon [TOC], 360 HI), oil-prone, immature to early oil mature source rock, representing a 25-m-thick condensed section, partly eroded over the Utsira high and thickening to 150–300 m toward the deep grabens. The underlying Heather Formation is also an oil-prone (4.4 wt.% TOC, 270 HI), 30- to 400-m-thick, more mature source rock. To map the TOC distribution using seismic, we performed detailed seismic interpretation and seismic attribute analysis following the petrophysical calibration of TOC with the [Formula: see text] ratio and P impedance on well data. Similar patterns of low-impedance high-TOC areas highlighted and mapped from the petrophysical studies at the Heather level were also observed on seismic relative acoustic impedance and amplitude maps over the study area. The poststack seismic data conditioning (structurally orientated noise reduction) improved the quality of the input megamerge seismic data and allowed the application of colored inversion, structural and fault imaging, as well as multiattribute combination and visualization techniques, which have been efficient in highlighting the distribution of high-TOC areas, structure and fault zones within the study area.

Stratigraphic Intervals for Oil and Tar Sand Deposits in the Uinta Basin, Utah

2017 ◽  
Vol 54 (4) ◽  
pp. 227-264
Author(s):  
Ronald Johnson ◽  
Justin Birdwell ◽  
Paul Lillis
Keyword(s):  
Brackish Water ◽  
Source Rocks ◽  
Uinta Basin ◽  
Green River ◽  
Reservoir Rocks ◽  
Stratigraphic Framework ◽  
Two Samples ◽  
The Rich ◽  
And Migration ◽  
Almost All

To better understand oil and bitumen generation and migration in the Paleogene lacustrine source rocks of the Uinta Basin, Utah, analyses of 182 oil samples and tar-impregnated intervals from 82 core holes were incorporated into a well-established stratigraphic framework for the basin. The oil samples are from the U.S. Geological Survey Energy Resources Program Geochemistry Laboratory Database; the tar-impregnated intervals are from core holes drilled at the Sunnyside and P.R. Spring-Hill Creek tar sands deposits. The stratigraphic framework includes transgressive and regressive phases of the early freshwater to near freshwater lacustrine interval of Lake Uinta and the rich and lean zone architecture developed for the later brackish-to-hypersaline stages of the lake. Two types of lacustrine-sourced oil are currently recognized in the Uinta Basin: (1) Green River A oils, with high wax and low β-carotane contents thought to be generated by source rocks in the fresh-to-brackish water lacustrine interval, and (2) much less common Green River B oils, an immature asphaltic oil with high β-carotane content thought to be generated by marginally mature to mature source rocks in the hypersaline lacustrine interval. Almost all oil samples from reservoir rocks in the fresh-to-brackish water interval are Green River A oils; however four samples of Green River A oils were present in the hypersaline interval, which likely indicates vertical migration. In addition, two samples of Green River B oil are from intervals that were assumed to contain only Green River A oil. Tar sand at the P.R. Spring-Hill Creek deposit are restricted to marginal lacustrine and fluvial sandstones deposited during the hypersaline phase of Lake Uinta, suggesting a genetic relationship to Green River B oils. Tar sand at the Sunnyside deposit, in contrast, occur in marginal lacustrine and alluvial sandstones deposited from the early fresh to nearly freshwater phase of Lake Uinta through the hypersaline phase. The Sunnyside deposit occurs in an area with structural dips that range from 7 to 14 degrees, and it is possible that some tar migrated stratigraphically down section.

Sequence stratigraphy of source and reservoir rocks in the Upper Permian and Jurassic of Jameson Land, East Greenland

1998 ◽  
pp. 43-54 ◽  
Author(s):  
Lars Stemmerik ◽  
Gregers Dam ◽  
Nanna Noe-Nygaard ◽  
Stefan Piasecki ◽  
Finn Surlyk
Keyword(s):  
Sequence Stratigraphy ◽  
Middle Jurassic ◽  
Sedimentary Basins ◽  
Upper Jurassic ◽  
Oil Field ◽  
Source Rocks ◽  
Upper Permian ◽  
Shallow Marine ◽  
East Greenland ◽  
Reservoir Rocks

NOTE: This article was published in a former series of GEUS Bulletin. Please use the original series name when citing this article, for example: Stemmerik, L., Dam, G., Noe-Nygaard, N., Piasecki, S., & Surlyk, F. (1998). Sequence stratigraphy of source and reservoir rocks in the Upper Permian and Jurassic of Jameson Land, East Greenland. Geology of Greenland Survey Bulletin, 180, 43-54. https://doi.org/10.34194/ggub.v180.5085 _______________ Approximately half of the hydrocarbons discovered in the North Atlantic petroleum provinces are found in sandstones of latest Triassic – Jurassic age with the Middle Jurassic Brent Group, and its correlatives, being the economically most important reservoir unit accounting for approximately 25% of the reserves. Hydrocarbons in these reservoirs are generated mainly from the Upper Jurassic Kimmeridge Clay and its correlatives with additional contributions from Middle Jurassic coal, Lower Jurassic marine shales and Devonian lacustrine shales. Equivalents to these deeply buried rocks crop out in the well-exposed sedimentary basins of East Greenland where more detailed studies are possible and these basins are frequently used for analogue studies (Fig. 1). Investigations in East Greenland have documented four major organic-rich shale units which are potential source rocks for hydrocarbons. They include marine shales of the Upper Permian Ravnefjeld Formation (Fig. 2), the Middle Jurassic Sortehat Formation and the Upper Jurassic Hareelv Formation (Fig. 4) and lacustrine shales of the uppermost Triassic – lowermost Jurassic Kap Stewart Group (Fig. 3; Surlyk et al. 1986b; Dam & Christiansen 1990; Christiansen et al. 1992, 1993; Dam et al. 1995; Krabbe 1996). Potential reservoir units include Upper Permian shallow marine platform and build-up carbonates of the Wegener Halvø Formation, lacustrine sandstones of the Rhaetian–Sinemurian Kap Stewart Group and marine sandstones of the Pliensbachian–Aalenian Neill Klinter Group, the Upper Bajocian – Callovian Pelion Formation and Upper Oxfordian – Kimmeridgian Hareelv Formation (Figs 2–4; Christiansen et al. 1992). The Jurassic sandstones of Jameson Land are well known as excellent analogues for hydrocarbon reservoirs in the northern North Sea and offshore mid-Norway. The best documented examples are the turbidite sands of the Hareelv Formation as an analogue for the Magnus oil field and the many Paleogene oil and gas fields, the shallow marine Pelion Formation as an analogue for the Brent Group in the Viking Graben and correlative Garn Group of the Norwegian Shelf, the Neill Klinter Group as an analogue for the Tilje, Ror, Ile and Not Formations and the Kap Stewart Group for the Åre Formation (Surlyk 1987, 1991; Dam & Surlyk 1995; Dam et al. 1995; Surlyk & Noe-Nygaard 1995; Engkilde & Surlyk in press). The presence of pre-Late Jurassic source rocks in Jameson Land suggests the presence of correlative source rocks offshore mid-Norway where the Upper Jurassic source rocks are not sufficiently deeply buried to generate hydrocarbons. The Upper Permian Ravnefjeld Formation in particular provides a useful source rock analogue both there and in more distant areas such as the Barents Sea. The present paper is a summary of a research project supported by the Danish Ministry of Environment and Energy (Piasecki et al. 1994). The aim of the project is to improve our understanding of the distribution of source and reservoir rocks by the application of sequence stratigraphy to the basin analysis. We have focused on the Upper Permian and uppermost Triassic– Jurassic successions where the presence of source and reservoir rocks are well documented from previous studies. Field work during the summer of 1993 included biostratigraphic, sedimentological and sequence stratigraphic studies of selected time slices and was supplemented by drilling of 11 shallow cores (Piasecki et al. 1994). The results so far arising from this work are collected in Piasecki et al. (1997), and the present summary highlights the petroleum-related implications.

Deep fluids and their role in hydrocarbon migration and oil deposit formation exemplified by supercritical СO2

2021 ◽  
pp. 1-11
Author(s):  
Sara LIFSHITS
Keyword(s):  
Supercritical Fluid ◽  
Oil And Gas ◽  
Gas Permeability ◽  
Sedimentary Rocks ◽  
Source Rocks ◽  
Reservoir Properties ◽  
Hydrocarbon Migration ◽  
Geological Processes ◽  
Before And After ◽  
Oil Source

ABSTRACT Hydrocarbon migration mechanism into a reservoir is one of the most controversial in oil and gas geology. The research aimed to study the effect of supercritical carbon dioxide (СО2) on the permeability of sedimentary rocks (carbonates, argillite, oil shale), which was assessed by the yield of chloroform extracts and gas permeability (carbonate, argillite) before and after the treatment of rocks with supercritical СО2. An increase in the permeability of dense potentially oil-source rocks has been noted, which is explained by the dissolution of carbonates to bicarbonates due to the high chemical activity of supercritical СО2 and water dissolved in it. Similarly, in geological processes, the introduction of deep supercritical fluid into sedimentary rocks can increase the permeability and, possibly, the porosity of rocks, which will facilitate the primary migration of hydrocarbons and improve the reservoir properties of the rocks. The considered mechanism of hydrocarbon migration in the flow of deep supercritical fluid makes it possible to revise the time and duration of the formation of gas–oil deposits decreasingly, as well as to explain features in the formation of various sources of hydrocarbons and observed inflow of oil into operating and exhausted wells.

Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

2021 ◽  
Vol 8 ◽  
pp. 55-79
Author(s):  
E. Bakhshi ◽  
A. Shahrabadi ◽  
N. Golsanami ◽  
Sh. Seyedsajadi ◽  
X. Liu ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Earth Model ◽  
Reservoir Properties ◽  
Stress Regime ◽  
Geomechanical Properties ◽  
Hydrocarbon Reservoir ◽  
Diagenetic Processes ◽  
Mechanical Earth Model ◽  
New Equation

The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.  

Characterization of Unconventional Reservoir for Development and Production: An Integrated Approach

2015 ◽  
Author(s):  
Omprakash Pal ◽  
Bilal Zoghbi ◽  
Waseem Abdul Razzaq
Keyword(s):  
Middle East ◽  
Integrated Approach ◽  
Advanced Technology ◽  
Additional Parameter ◽  
Unconventional Reservoir ◽  
Reservoir Properties ◽  
Capillary Suction ◽  
Geomechanical Properties ◽  
Oil Companies ◽  
Geochemical Properties

Abstract Unconventional reservoir exploration and development activities in the Middle East have increased and are expected to continue to do so. National oil companies in the Middle East have a strategy for maximizing oil exports as well as use of natural gas. This has placed emphasis on use of advanced technology to extend the lives of conventional reservoirs and more activities in terms of “unconventional gas and oil.” Understanding unconventional environments, such as shale reservoirs, requires unique processes and technologies based on reservoir properties for optimum reservoir production and well life. The objective of this study is to provide the systematic work flow to characterize unconventional reservoir formation. This paper discusses detailed laboratory testing to determine geochemical, rock mechanical, and formation fluid properties for reservoir development. Each test is described in addition to its importance to the reservoir study. Geochemical properties, such as total organic carbon (TOC) content to evaluate potential candidates for hydrocarbon, mineralogy to determine the formation type and clay content, and kerogen typing for reservoir maturity. Formation fluid sensitivity, such as acid solubility testing of the formation, capillary suction time testing, and Brinell hardness testing, are characterized to better understand the interaction of various fluids with the formation to help optimize well development. An additional parameter in unconventional reservoirs is to plan ahead when implementing the proper fracturing stimulation technique and treatment design, which requires determining the geomechanical properties of the reservoir as well as the fluid to be used for stimulation. Properties of each reservoir are unique and require unique approaches to design and conduct fracturing solutions. The importance of geomechanical properties is discussed here. This paper can be used to help operators obtain a broad overview of the reservoir to determine the best completion and stimulation approaches for unconventional development.

scholarly journals The Cambrian Henson Gletscher Formation: a mature to postmature hydrocarbon source rock sequence from North Greenland

1987 ◽  
Vol 133 ◽  
pp. 141-157
Author(s):  
F.G Christiansen ◽  
H Nøhr-Hansen ◽  
O Nykjær
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Source Rock ◽  
Reservoir Rocks ◽  
Potential Source ◽  
Potential Reservoir ◽  
Field Season ◽  
North Greenland

During the 1985 field season the Cambrian Henson Gletscher Formation in central North Greenland was studied in detail with the aim of evaluating its potential as a hydrocarbon source rock. The formation contains organic rich shale and carbonate mudstone which are considered to be potential source rocks. These are sedimentologically coupled with a sequence of sandstones and coarse carbonates which might be potential reservoir rocks or migration conduits. Most of the rocks exposed on the surface are, however, thermally mature to postrnature with respect to hydrocarbon generation, leaving only few chances of finding trapped oil in the subsurface of the area studied in detail.

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