scholarly journals Analysis of Geologic CO2 Migration Pathways in Farnsworth Field, NW Anadarko Basin

Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7818
Author(s):  
Jolante van Wijk ◽  
Noah Hobbs ◽  
Peter Rose ◽  
Michael Mella ◽  
Gary Axen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Petroleum System ◽  
Oil Field ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Tracer Study ◽  
Deep Basin ◽  
Anadarko Basin ◽  
System Models ◽  
Migration Pathways

This study reports on analyses of natural, geologic CO2 migration paths in Farnsworth Oil Field, northern Texas, where CO2 was injected into the Pennsylvanian Morrow B reservoir as part of enhanced oil recovery and carbon sequestration efforts. We interpret 2D and 3D seismic reflection datasets of the study site, which is located on the western flank of the Anadarko basin, and compare our seismic interpretations with results from a tracer study. Petroleum system models are developed to understand the petroleum system and petroleum- and CO2-migration pathways. We find no evidence of seismically resolvable faults in Farnsworth Field, but interpret a karst structure, erosional structures, and incised valleys. These interpretations are compared with results of a Morrow B well-to-well tracer study that suggests that inter-well flow is up-dip or lateral. Southeastward fluid flow is inhibited by dip direction, thinning, and draping of the Morrow B reservoir over a deeper, eroded formation. Petroleum system models predict a deep basin-ward increase in temperature and maturation of the source rocks. In the northwestern Anadarko Basin, petroleum migration was generally up-dip with local exceptions; the Morrow B sandstone was likely charged by formations both below and overlying the reservoir rock. Based on this analysis, we conclude that CO2 escape in Farnsworth Field via geologic pathways such as tectonic faults is unlikely. Abandoned or aged wellbores remain a risk for CO2 escape from the reservoir formation and deserve further monitoring and research.

scholarly journals Petroleum System Modelling of the Akri-Bijeel Oil Field, Northern Iraq: Insights From 1-Dimensional Basin Modelling

2020 ◽  
Vol 4 (2) ◽  
pp. 35-47
Author(s):  
Rzger Abdula ◽  
Hema Hassan ◽  
Maryam Sliwa
Keyword(s):  
Lower Cretaceous ◽  
Vitrinite Reflectance ◽  
Petroleum System ◽  
Oil Field ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Maturity Stage ◽  
System Modelling ◽  
Northern Iraq ◽  
High Maturity

The petroleum system of the Akri-Bijeel oil field shows that the Palaeogene formations such as the Kolosh Formation seem to be immature. However, the Jurassic–Lower Cretaceous source rocks such as those from the Chia Gara, Naokelekan, and Sargelu formations are thermally mature and within the main oil window because their vitrinite reflectance (Ro%) values are >0.55%. The Triassic Kurra Chine and Geli Khana formations are thought to be in the high maturity stage with Ro values ≥1.3% and within the wet and dry gas windows, whereas the older formations are either within the dry gas zone or completely generated hydrocarbon stage and depleted after the hydrocarbons were expelled with subsequent migration to the reservoir rock of the structural traps.

Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in South of Sultanate of Oman

2021 ◽  
Author(s):  
Ali Reham Al-Jabri ◽  
Rouhollah Farajzadeh ◽  
Abdullah Alkindi ◽  
Rifaat Al-Mjeni ◽  
David Rousseau ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
History Matching ◽  
Oil Field ◽  
Reservoir Rock ◽  
Sultanate Of Oman ◽  
Industrial Chemicals ◽  
Oil Viscosity ◽  
Injection Strategy ◽  
Operational Conditions

Abstract Heavy oil reservoirs remain challenging for surfactant-based EOR. In particular, selecting fine-tuned and cost effective chemical formulations requires extensive laboratory work and a solid methodology. This paper reports a laboratory feasibility study, aiming at designing a surfactant-polymer pilot for a heavy oil field with an oil viscosity of ~500cP in the South of Sultanate of Oman, where polymer flooding has already been successfully trialed. A major driver was to design a simple chemical EOR method, to minimize the risk of operational issues (e.g. scaling) and ensure smooth logistics on the field. To that end, a dedicated alkaline-free and solvent-free surfactant polymer (SP) formulation has been designed, with its sole three components, polymer, surfactant and co-surfactant, being readily available industrial chemicals. This part of the work has been reported in a previous paper. A comprehensive set of oil recovery coreflood tests has then been carried out with two objectives: validate the intrinsic performances of the SP formulation in terms of residual oil mobilization and establish an optimal injection strategy to maximize oil recovery with minimal surfactant dosage. The 10 coreflood tests performed involved: Bentheimer sandstone, for baseline assessments on large plugs with minimized experimental uncertainties; homogeneous artificial sand and clays granular packs built to have representative mineralogical composition, for tuning of the injection parameters; native reservoir rock plugs, unstacked in order to avoid any bias, to validate the injection strategy in fully representative conditions. All surfactant injections were performed after long polymer injections, to mimic the operational conditions in the field. Under injection of "infinite" slugs of the SP formulation, all tests have led to tertiary recoveries of more than 88% of the remaining oil after waterflood with final oil saturations of less than 5%. When short slugs of SP formulation were injected, tertiary recoveries were larger than 70% ROIP with final oil saturations less than 10%. The final optimized test on a reservoir rock plug, which was selected after an extensive review of the petrophysical and mineralogical properties of the available reservoir cores, led to a tertiary recovery of 90% ROIP with a final oil saturation of 2%, after injection of 0.35 PV of SP formulation at 6 g/L total surfactant concentration, with surfactant losses of 0.14 mg-surfactant/g(rock). Further optimization will allow accelerating oil bank arrival and reducing the large PV of chase polymer needed to mobilize the liberated oil. An additional part of the work consisted in generating the parameters needed for reservoir scale simulation. This required dedicated laboratory assays and history matching simulations of which the results are presented and discussed. These outcomes validate, at lab scale, the feasibility of a surfactant polymer process for the heavy oil field investigated. As there has been no published field test of SP injection in heavy oil, this work may also open the way to a new range of field applications.

scholarly journals Analysis of Petroleum System for Exploration and Risk Reduction in Abu Madi/Elqar'a Gas Field, Nile Delta, Egypt

2012 ◽  
Vol 2012 ◽  
pp. 1-10 ◽  
Author(s):  
Said Keshta ◽  
Farouk J. Metwalli ◽  
H. S. Al Arabi
Keyword(s):  
Nile Delta ◽  
Organic Matter Content ◽  
Petroleum System ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Basin Modeling ◽  
Burial History ◽  
Gas Field ◽  
Upper Miocene ◽  
Migration Pathways

Abu Madi/El Qar'a is a giant field located in the north eastern part of Nile Delta and is an important hydrocarbon province in Egypt, but the origin of hydrocarbons and their migration are not fully understood. In this paper, organic matter content, type, and maturity of source rocks have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. Modeling of the empirical data of source rock suggests that the Abu Madi formation entered the oil in the middle to upper Miocene, while the Sidi Salem formation entered the oil window in the lower Miocene. Charge risks increase in the deeper basin megasequences in which migration hydrocarbons must traverse the basin updip. The migration pathways were principally lateral ramps and faults which enabled migration into the shallower middle to upper Miocene reservoirs. Basin modeling that incorporated an analysis of the petroleum system in the Abu Madi/El Qar'a field can help guide the next exploration phase, while oil exploration is now focused along post-late Miocene migration paths. These results suggest that deeper sections may have reservoirs charged with significant unrealized gas potential.

scholarly journals Analysis of the Petroleum System of Dima Oil Field by Using PetroMoD 1D

2021 ◽  
pp. 526-531
Author(s):  
Haider A. F. Al-Tarim
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Petroleum System ◽  
Oil Field ◽  
Reservoir Rock ◽  
Geological Time ◽  
Reservoir Rocks ◽  
Petroleum Systems ◽  
Geological Age ◽  
Stratigraphic Succession

The study of petroleum systems by using the PetroMoD 1D software is one of the most prominent ways to reduce risks in the exploration of oil and gas by ensuring the existence of hydrocarbons before drilling.      The petroleum system model was designed for Dima-1 well by inserting several parameters into the software, which included the stratigraphic succession of the formations penetrating the well, the depths of the upper parts of these formations, and the thickness of each formation. In addition, other related parameters were investigated, such as lithology, geological age, periods of sedimentation, periods of erosion or non-deposition, nature of units (source or reservoir rocks), total organic carbon (TOC), hydrogen index (HI) ratio of source rock units, temperature of both surface and formations as they are available, and well-bottom temperature.      Through analyzing the models by the evaluation of the source rock units, the petrophysical properties of reservoir rock units, and thermal gradation with the depth during the geological time, it became possible to clarify the elements and processes of the petroleum system of the field of Dima. It could be stated that Nahr Umr, Zubair, and Sulaiy formations represent the petroleum system elements of Dima-1 well.

scholarly journals A Data Mining Perspective on the Confluent Ions` Effect for Target Functionality

2021 ◽  
Vol 2 (3) ◽  
pp. 202-215
Author(s):  
Babak Fazelabdolabadi ◽  
Mostafa Montazeri ◽  
Peyman Pourafshary
Keyword(s):  
Data Mining ◽  
Oil Recovery ◽  
Recursive Partitioning ◽  
Oil Field ◽  
Reservoir Rock ◽  
Single Type ◽  
Relative Significance ◽  
New Perspective ◽  
Permeability Impairment ◽  
Ion Species

The production of hydrocarbon resources at an oil field is concomitant with challenges with respect to the formation of scale inside the reservoir rock – intricately impairing its permeability and hindering the flow. Historically, the effect of ions is attributed to the undergone phenomenon; nevertheless, there exists a great deal of ambiguity about its relative significance compared to other factors, or the effectiveness as per the ion type. The present work applies a data mining strategy to unveil the influencing hierarchy of the parameters involved in driving the process within major rock categories – sandstone and carbonate – to regulate a target functionality. The functionalities considered evolve around maximizing the oil recovery, minimizing permeability impairment/ scale damage. A pool of experimental as well as field data was used for this sake, accumulating the bulk of the available literature data. The methods used for data analysis in the present work included the Bayesian Network, Random Forest, Deep Neural Network, as well as Recursive Partitioning. The results indicate a rolling importance for different ion species - altering under each functionality – which is not ranked as the most influential parameter in either case. For the oil recovery target, our results quantify a distinction between the source of ion of a single type, in terms of its influencing rank in the process. This latter deduction is the first proposal of its kind – suggesting a new perspective for research. Moreover, the machine learning methodology was found to be capable of reliably capturing the data – evidenced by the minimal errors in the bootstrapped results. Doi: 10.28991/HIJ-2021-02-03-05 Full Text: PDF

A NEW MODEL FOR THE HUTTON/BIRKHEAD RESERVOIR/SEAL COUPLET AND THE ASSOCIATED BIRKHEAD-HUTTON(!) PETROLEUM SYSTEM

1998 ◽  
Vol 38 (1) ◽  
pp. 724 ◽  
Author(s):  
P.J. Boult ◽  
E. Lanzilli ◽  
B.H. Michaelsen ◽  
D.M. McKirdy ◽  
M.J. Ryan
Keyword(s):  
Weak Link ◽  
Petroleum System ◽  
Source Rocks ◽  
Age Dating ◽  
New Model ◽  
Biomarker Analysis ◽  
Seismic Sequence Stratigraphy ◽  
Migration Pathways ◽  
Live Oil ◽  
Eromanga Basin

Biomarker analysis of source rocks and oils from the Permian and Jurassic of the central Patchawarra Trough and the Gidgealpa area, reveal that much of the oil in the Eromanga Basin may have a significant lateral migrational component and be of Jurassic (i.e. intra-Eromanga) origin. Differences in hopane signatures can be used to discriminate between palaeo-oil and presently migrating live oil, and to constrain migration pathways. Thus, in some locations the identification of new source kitchens has been made possible by a combination of seal and biomarker analysis taking into account stratigraphic inheritance on conventional structural drainage maps. 3D seismic, sequence stratigraphy, dipmeter interpretation and neodymium model age dating together with conventional correlation techniques, have provided a new model for the deposition of the Hutton Sandstone to Birkhead Formation transition in the Eromanga Basin. Analysis of seal and carrier bed properties through time, in combination with hydrocarbon geochemistry and thermal modelling, indicates that the Birkhead-Hutton (!)' petroleum system has produced significant quantities of oil in the Cooper Basin sector of the Eromanga Basin.A disconf ormity near the base of the Hutton/Birkhead transition has controlled the location of oil-prone source rocks within the Birkhead Formation and stratigraphically focussed migration along palaeo-topographic ridges. A diachronous influx of volcanic-arc-derived (VAD) sediment within the Birkhead Formation has been traced right across the productive part of the Eromanga Basin. This influx of VAD sediment is associated with the main seal to underlying accumulations within both the lower Birkhead Formation and Hutton Sandstone. Sands comprising VAD sediment, which are juxtaposed, form the weak link within the main seal. The sediments between the VAD influx and the underlying unconformity in many locations constitute a waste zone.Palaeo-oil columns are common beneath extant, live oil accumulations. This indicates that a possible decrease in seal potential of the VAD sediment has occurred over time. The main seals to underlying accumulations were originally static, water-wet capillary seals which, mostly through an alteration of wettability, changed to simple permeability seals for currently migrating oil. Seal analysis, biomarker studies and geothermal modelling indicate that a double migration pulse has occurred in some areas of the Eromanga Basin. Palaeo-oil columns are related to a Late Cretaceous charge, and live oil accumulations to presently migrating oil.

scholarly journals Comparative Study of an Enhanced Oil Recovery process with various chemicals for Naharkatiya Oil Field

2014 ◽  
Vol 2 (4) ◽  
pp. 432-436 ◽  
Author(s):  
Kalpajit Hazarika ◽  
Subrata Borgohain Gogoi
Keyword(s):  
Comparative Study ◽  
Oil Recovery ◽  
Black Liquor ◽  
Recovery Process ◽  
Paper Mill ◽  
Oil Field ◽  
Reservoir Rock ◽  
Surfactant Adsorption ◽  
Recovery Efficiency

This paper reports the effect of using black liquor whose main constituent is Na- lignosulfonate, which is the effluent from Nagaon paper Mill, Jagiroad, Assam, along with Alkali and Co-surfactant in enhanced crude oil recovery from Upper Assam porous media. In this paper an attempt has been done to study the change in Inter Facial Tension (IFT) with different concentration of Surfactant and also a comparative study has been done determine the change in IFT with or without Alkali and Co-Surfactant. Increasing the surfactant concentration reduces the IFT, hence increases the recovery efficiency. Alkali changes the Wettability of reservoir rock and reduces the surfactant adsorption and also act as an in-situ surfactant production.DOI: http://dx.doi.org/10.3126/ijasbt.v2i4.11047 Int J Appl Sci Biotechnol, Vol. 2(4): 432-436 

Waterflood Oil Recovery in Fractured Reservoirs With Directionally Drilled Wells

1984 ◽  
Vol 24 (04) ◽  
pp. 375-381 ◽  
Author(s):  
Jeffrey R. Bacon ◽  
Robert H. Kempthorne
Keyword(s):  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Development Planning ◽  
Oil Field ◽  
Oil Reservoirs ◽  
Reservoir Rock ◽  
Vertical Position ◽  
Oil Reservoir ◽  
Directional Drilling ◽  
Initial Development

Abstract A technique has been developed to estimate the potential effects of directionally drilled wellbore orientation on pattern waterflood oil recovery in anisotropically fractured reservoirs. The technique attempts to quantify the tradeoff between drilling directional wells either more vertically or better aligned with the major fracture orientation in situations where simple vertical wells are not possible. Among the incentives to deplete some reservoirs with directionally drilled wells are the ability to access reserves located beneath large bodies of water from shore or island structures and the economy of centralized surface facilities. The orientation of these directionally drilled wells in anisotropically fractured oil reservoirs may have a significant impact on recovery efficiency. The described method involves combining the directional permeability characteristics of the reservoir caused by fractures, drilling accuracy, and the proposed wellbore orientation to estimate the volume of reservoir that may be affected by a nonvertical well. The distribution of fractures in the reservoir, average fracture length, and effective vertical permeability are noted as being major factors influencing the effect of directionally drilled wells on oil recovery. When applied to the Norman Wells oil field (N.W. Ter., Canada), it was possible to identify elongated target areas within which any directionally drilled well is expected to have similar oil recovery. Introduction Recent advances in drilling technology have made it possible to drill wellbores deviated from the normal vertical position, up to and including completely horizontal. This type of directional drilling will allow the depletion of oil reservoirs that are located beneath surface obstacles by drilling wells from remote surface locations. Access to many of the world's remaining petroleum reserves, in such offshore areas as the Canadian Beaufort Sea and the east coast, will have to be by drilling from conveniently located island or platform structures. The Norman Wells oil reservoir, of which approximately 60% lies beneath the MacKenzie River, is a current example of how directional drilling will make oil recovery possible. The proposed reservoir depletion program involves drilling wells from centralized surface facilities to program involves drilling wells from centralized surface facilities to implement a pattern waterflood oil-recovery scheme (Fig. 1). The wells will be deviated at as much as 700 to the vertical to reach the target locations from the centralized surface locations (Fig. 2). The reservoir rock is anisotropically fractured, and optimization of the wellbore orientation with respect to the fractures was recognized as an area of study with considerable potential for increasing oil recovery. Initial development planning indicated that wells should be as vertical as possible and aligned with the main fracture trend. This simple guideline resulted in many technically impossible wells and wells with poor anticipated oil recovery. The optimization procedure developed here subsequently was applied in the development planning of the Norman Wells reservoir and is believed to have helped maximize oil recovery while maintaining technically feasible and economically viable well designs. Background geological data and details of the proposed Norman Wells development plan are documented in Refs. 1 and 2. Theory Several analytical methods have been presented for determining the vertical and areal sweep efficiencies of pattern waterflood operations. These methods, or more sophisticated reservoir simulation techniques, may be employed to determine the recoverable reserves associated with the waterflooding of homogeneous reservoirs or reservoirs composed of discrete homogeneous units. The presence of fractures in an oil reservoir adds a new dimension to this problem because the flow characteristics of fractured rock systems are difficult to predict. SPEJ p. 375

Designing a Robust Surfactant Based SP Formulation in High Clay Containing Low Permeability Indonesian Field

2021 ◽  
Author(s):  
Andi Bachtiar ◽  
Octaviani Octaviani ◽  
Iqbal Fauzi ◽  
Sayak Roy ◽  
Roberto Company ◽  
...  
Keyword(s):  
Oil Recovery ◽  
High Throughput Screening ◽  
Lessons Learned ◽  
Oil Field ◽  
Reservoir Rock ◽  
Low Permeability ◽  
Screening Experiments ◽  
Main Challenge ◽  
Chemical Eor ◽  
Rock Characterization

Abstract Indonesian oil and gas reserves have been depleting since 2000 with no major addition of new oil reserves. Therefore, it is imperative to increase national oil production by optimizing the mature fields through the implementation of successful EOR technology. Out of this approach, a comprehensive study has been carried out on the targeted field by exploring the potential of surfactant-polymer (SP) flooding. This article describes the formulation design, optimization, and lessons learned leading up to a successful and robust chemical EOR formulation designing for a low permeability and high clay (>20% clay) containing Indonesian oil field. The detailed workflow consists of analysis of fluid and rock characterization, tailor-made SP formulation designing, optimization and coreflood validation as presented in previous papers (Bazin, 2010). A series of surfactant formulation were designed and screened synthetically through a validated High Throughput Screening (HTS) methodology using a robotic platform combined with microfluidic tools for ultra-low interfacial tension (IFT), solubility, compatibility with brine and polymer. Rock mineralogy has played an important role due to heterogeneity and very high (>20%) clay content. Surfactants retention through adsorption on reservoir rocks was the main constraint to achieve high performance and economical chemical EOR for the targeted field. Specific strategies by optimizing the surfactant formulation and by injecting adsorption inhibitor thus needed to be deployed to mitigate high surfactant retention. The detailed laboratory screening experiments conclude that the designed robust SP formulation is able to induce ultra-low IFT, excellent solubility and compatibility at the injection water salinity. The dynamic coreflood experiment using reservoir rock shows high incremental oil recovery (>60% ROIP) in short SP slug injection. As expected from the nature of rock, adsorption was the main challenge encountered during the course of this study, which resulted in a very promising oil recovery in economically realistic conditions.

Burial History Reconstruction of the Appalachian Basin in Kentucky, West Virginia, Pennsylvania, and New York, Using 1D Petroleum System Models

2019 ◽  
Vol 56 (4) ◽  
pp. 365-396
Author(s):  
Debra Higley ◽  
Catherine Enomoto
Keyword(s):  
New York ◽  
Vitrinite Reflectance ◽  
Structural Complexity ◽  
Appalachian Basin ◽  
Source Rocks ◽  
Burial History ◽  
Gas Generation ◽  
Deep Basin ◽  
Utica Shale ◽  
Wet Gas

Nine 1D burial history models were built across the Appalachian basin to reconstruct the burial, erosional, and thermal maturation histories of contained petroleum source rocks. Models were calibrated to measured downhole temperatures, and to vitrinite reflectance (% Ro) data for Devonian through Pennsylvanian source rocks. The highest levels of thermal maturity in petroleum source rocks are within and proximal to the Rome trough in the deep basin, which are also within the confluence of increased structural complexity and associated faulting, overpressured Devonian shales, and thick intervals of salt in the underlying Silurian Salina Group. Models incorporate minor erosion from 260 to 140 million years ago (Ma) that allows for extended burial and heating of underlying strata. Two modeled times of increased erosion, from 140 to 90 Ma and 23 to 5.3 Ma, are followed by lesser erosion from 5.3 Ma to Present. Absent strata are mainly Permian shales and sandstone; thickness of these removed layers increased from about 6200 ft (1890 m) west of the Rome trough to as much as 9650 ft (2940 m) within the trough. The onset of oil generation based on 0.6% Ro ranges from 387 to 306 Ma for the Utica Shale, and 359 to 282 Ma for Middle Devonian to basal Mississippian shales. The ~1.2% Ro onset of wet gas generation ranges from 360 to 281 Ma in the Utica Shale, and 298 to 150 Ma for Devonian to lowermost Mississippian shales.

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