This three-day course presents the basics of petroleum geology with an emphasis on unconventional oil and natural gas reservoirs of clastic and carbonate origin. Lectures are supplemented with case examples from classic resource plays in western Canada. Topics include the fundamental principles of sedimentary geology as applied to hydrocarbon exploration and reservoir development, the stratigraphy of Western Canada, the origin and heterogeneity of conglomerate, sandstone, siltstone and carbonate reservoirs and a review of the unique properties of shale as source rocks and hydrocarbon reservoirs. Other topics include clastic and carbonate environments of deposition, reservoir quality and architecture and the lateral variability and heterogeneity of clastic and carbonate reservoirs as applied to the predictability of outcomes in horizontal drilling. Included are printed course notes and a half-day session at the Alberta Energy Regulator (AER) Core Research Centre in Calgary to examine first- hand the rock properties of clastic and carbonate conventional and unconventional (i.e.
Lacaze, Sébastien (Eliis SAS. Parc Mermoz, Immeuble l’Onyx, 187 rue Hélène Boucher, 34170 Castelnau-Le-Lez, France) | Philit, Sven (Eliis SAS. Parc Mermoz, Immeuble l’Onyx, 187 rue Hélène Boucher, 34170 Castelnau-Le-Lez, France) | Pauget, Fabien (Eliis SAS. Parc Mermoz, Immeuble l’Onyx, 187 rue Hélène Boucher, 34170 Castelnau-Le-Lez, France) | Wilson, Thomas (Eliis Pty Ltd, 191 St Georges Terrace, Perth WA 6000, Australia)
Summary Structural interpretation from 2D seismic line sets is common in the hydrocarbon exploration process. Generally, this process consists in the interpretation of several key horizons on the several seismic lines available, which is time-demanding. Furthermore, as the seismic lines are often processed differently, misties are frequently observed between the lines, which may lead to cumbersome interpretation. In this paper, we introduce a method aiming at providing an efficient 2D line seismic interpretation answering the need of obtaining early 3D geological model during reservoir exploration. Introduction Traditional 2D seismic interpretation is generally a complex and time-consuming task which relies on 2D autotracking and the manual picking of a few stratigraphic events on every line.
Seacroft Marine Consultants named Richard Pearce marine engineering and dynamic poisitioning (DP) manager. Pearce has 16 years of experience in engineering and technical disciplines of the marine and offshore industry. He most recently served as technical manager of the Fletcher Group and as service delivery manager at Bibby Offshore, where he was responsible for operation of the company's offshore support vessels.
Detailed knowledge of fill-spill history and charge entry points to fields is rarely available, due to lack of suitable data sets and methodologies. This paper describes the application of a reservoir geochemical work flow (multi-variate statistical analysis of geochemical data) to unravel the fill history of a highly complex oil field in the northern Gulf of Thailand, and the implications of these results in assessing charge risk in adjacent and near-field prospects.
The Jasmine-Ban Yen field, Pattani Trough, Gulf of Thailand, produces from stacked Middle to Late Miocene clastic reservoirs, draped over a highly faulted structural nose. In an earlier study, 59 oils from across the field underwent standardised fingerprinting, biomarker and bulk isotope analysis. Here, geochemical parameters considered resistant to secondary processes such as biodegradation, underwent hierarchical cluster analysis and classification into fluid families. Distinct families potentially represent fluids that share a common history. The results were synthesised with spatial information, seismic data, reservoir pressures, petroleum systems modelling, and observations drawn from the field's production history, to elucidate the fill-spill history of the field.
All oils were expelled from similar lacustrine organofacies at similar maturity, which is broadly consistent with a single source pod charging the field. The closest mature kitchen is thought to be located in the Northern Pattani Trough, some 20 to 25 km to the south. A sub-regional Middle Miocene lacustrine seal, the "hot shale," focusses oil into the Jasmine-Ban Yen field, and forms the seal for 30% of the STOIIP. Fluids also occur in reservoirs above this seal, which could be emplaced either through vertical fill and spill via high offset faults, possibly aided by locally high CO2 increasing buoyancy pressure by formation of a gas cap, or laterally, via spill from adjacent fault blocks. Detailed knowledge of charge history remains elusive; however, the occurrence of consistently different fluid families above and below the hot shale seal, with fluids below represented by consistent families over a lateral distance of 12 km, supports an interpretation of multiple entry points into the field. Aromatic maturity parameters indicate that four Ban Yen samples are of slightly elevated maturity, suggesting that late charge accesses the field above the hot shale. The possibility that the differences between families are related to biodegradation was investigated and discarded. Families probably represent discrete, lateral spill pathways reflecting multiple charge entry points and are differentiated by subtle variations in organofacies related to oxicity and contribution from plant material. Comparable migration above and below the hot shale into B5/27 is a possibility, and exploration prospectivity is risked accordingly.
Placing statistically derived fluid families into a spatial, geological and production context enables unravelling of migration vectors in complex fields. Furthermore, inferences may be drawn from such a study that can help guide risk assignment to offset exploration prospectivity.
Grijalva, O. (Clausthal University of Technology) | Holzmann, J. (Clausthal University of Technology) | Oppelt, J. (Clausthal University of Technology) | Perozo, N. (Clausthal University of Technology) | Paz, C. (Clausthal University of Technology) | Asgharzadeh, A. (Clausthal University of Technology)
The technique of drilling a well using the casing string has earned itself a well deserved place as one of the most effective and cost-saving ways to drill and complete a hydrocarbon well; the cornerstone of this is the casing pipe, composed by the pipe body itself and the threaded connection. Normally an API-Buttress type connector is used; nevertheless, it has been proven in both controlled and field conditions that this connector is not completely adequate for Casing Drilling per se, as high torque capacities are demanded. Apart from that, and due to this condition, the constant need for using torque enhancers represents a high limitation to the Drilling with Casing technique itself. For this, Premium-type connectors address this point in a more proper way in form of improved geometries in thread and shoulder profiles and enhanced sealing capabilities.
Despite of this, Premium Connections are seldom used in Casing Drilling applications, being them almost relegated to very special, seldom drilling deployments. However, successful use of Premium Connections in Casing Drilling projects offshore Australia, Norway and onshore Mexico are paving the road for an intensive inclusion of Premium Connections in the field; this has also come as the result of the current diversification of the OCTG market for this connectors coming after a better understanding of load distribution and torque "control" by means of improved geometric design combined with the successful integration of axial-symmetric modeling (Finite Element Method) and Full Scale Testing for design and validation of new couplings. In this work, a holistic approach will address the technological highlights making up the past and current market offer and future tendencies in OCTG specialty connectors for casing drilling, understanding this as the direct result of the evolution of this drilling technique and the recent improvements in Full Scale Testing and computer-assisted design.
It was observed that the drilling of horizontal sections with a casing string in some field developments worldwide was only possible between 1990-2010 due to important modifications made to Full Scale Testing procedures employed to validate newly designed Premium Connections. In this case, the inclusion of a testing stage with bending broadened the usage spectrum in which some Premium Connection geometries were able to perform well; this serves as a concise, yet significative example of the constant evolution the OCTG sector underwent in the last decades, and also a great example of the superb applicability of Premium Connections in high demanding oilfield operations like drilling a well with casing pipe.
This work brings new light into the understanding of the potential of Premium Connections as a standard selection parameter for OCTG used in Casing Drilling, understanding the combined usage both technologies as a clear warrant towards well integrity.
Ainsworth, R. B. (Chevron Australia Pty. Ltd.) | Payenberg, T. H. D. (Chevron Australia Pty. Ltd.) | Willis, B. J. (Chevron Energy Technology Company) | Sixsmith, P. J. (Chevron Energy Technology Company) | Yeaton, J. W. (Chevron Australia Pty. Ltd.) | Sykiotis, N. (Chevron Australia Pty. Ltd.) | Lang, S. C. (Chevron Australia Pty. Ltd.)
Reservoir delineation and characterisation of the shallow marine Triassic Brigadier Formation (Fm.), northwest shelf (NWS), Australia is challenged by the thin-bedded nature of the reservoir. These reservoirs are generally below seismic resolution in stark contrast to the underlying, seismically well-imaged Mungaroo Formation fluvial channel belt reservoirs. In the absence of clear seismic definition of reservoir distribution, development of reservoir models for the Brigadier Fm. rely heavily on conceptual depositional models refined by reference to depositional analogues.
The Brigadier Fm. intervals currently under development in the Northern Carnarvon Basin are typically 120 m thick with overall 50–80% NTG. Strata in this interval are generally structurally inclined in tilted fault blocks and sub-crop an angular unconformity (IJU) with overlying sealing shales. Although the general geometry of the inclined strata is imaged on seismic, poor impedance contrasts do not allow definition of individual sheet-like, five to 10 m thick depositional elements or internal lithic variations that could be used to confidently target development wells. Thick stacked successions of thin reservoirs separated by shale produce correlation uncertainties between wells and make it challenging to predict spatial trends in reservoir quality. In order to better predict vertical and lateral facies patterns within the Brigadier Fm., a novel approach of reservoir mapping and model construction was developed that deterministically predicts reservoir distribution and connectivity based on conceptual depositional models.
A revised Brigadier Fm. stratigraphic framework was created across the sub-regional (88 km x 64 km) study area by integrating the latest sedimentology, biostratigraphy, chemostratigraphy and seismic data. Depositional models of the Brigadier Fm. were reviewed by re-examining core using a depositional-process classification that defined reservoir-element-scale bodies within correlated stratigraphic intervals. Two key depositional scenarios were developed; an asymmetrical, wave-dominated delta model, and an alternative fluvial-dominated delta model. The Mitchell River Delta, north-west Queensland, Australia, was used as a partial analogue to define shapes and scaling of the subsurface depositional elements and their internal lithic patterns.
The sub-regional model produced for the study was built in flattened stratigraphic space. Depositional geometries were extracted from this model and morphed into structured space over specific fields. The hierarchical nature of the model enables seamless analysis of exploration to development scale issues. The model is currently being tested by predicting and verifying the vertical facies successions for exploration, appraisal and development wells, and dynamic flow data from well tests.
Borehole instability is one of the major factors that contribute significantly to additional unplanned cost in drilling operations irrespective of the wellbore inclination. Problems generally build up in time, starting with the tensile or compressive failure of the borehole wall, followed by transfer of fragments to the annulus and finally-if hole cleaning is insufficient-culminating in such difficulties as tight hole, breakouts, caving, pack off, borehole collapse and stuck pipe.
Horizontal and highly deviated wells in normal faults stress regimes present more difficult challenges than low inclined wells due to compressive or shear failure of the wellbore. Wellbore stability issues are more pronounced as the wellbore stress difference reaches at maximum with increase in inclination. Proper planning of the well trajectory and mud weights are crucial to avoid such complexity which causes huge rig downtime, NPT and cost. With the aid of in-situ stress, pore pressure and rock strength analysis the wellbore stability can be assured with suggested optimum deviation profile and mud weights window for different inclinations and azimuths.
An attempt has been made to perform the wellbore stability analysis for three high angle and three horizontal wells (with drain-extension of about 500ftahd) development wells in Niger Delta which is planned for production in near future. In our workflow, the seismic data and offset well information have been incorporated to generate pore pressure, optimum mudweight, shear failure (minimum envelope) and fracture pressure gradient. Rock physical parameters have been calculated from the offset well's logs and calibrated with laboratory tested dataset to use in the stability analysis for well KTY 02, KTY 03 and KTY 04. In the study area, wellbore stability analysis was carried out in both the pilot and drain hole sections of the horizontal wells. However, because of horizontal drilling plan in drain holes, differences in principal stresses in the wellbore and their physical implication on stability was plotted and interpreted through stress concentration plot and safe MW window analyzer extensively. The stresses and the rock strength datasets input were used to derive the collapse failure gradient curve (CFG) using the Mogi failure criteria. The wellbore circumferential and radial stress distribution analysis has been done for different depths with the inputs from stresses and the corresponding cohesive strengths and the Frictional Angles.
With these analytical results, we have recommended the wellbore trajectory along Shmin and SHmax direction and along the maximum good reservoir facies with corresponding mud weight (window) profile required to drill these wells with NPT as a result of instability consequences such as stuck pipes and jeopardizing wellbore integrity during logging, casing running and completions.
Wu, Xingru (University of Oklahoma) | Babatola, Feyidamilola (Linde Process Plants) | Jiang, Lei (Rhombus Energy Solutions) | Tolbert, Brandon T. (University of Oklahoma) | Liu, Junrong (China University of Petroleum (East China))
Subsea processing is an evolving technology in response to ultradeepwater hydrocarbon development and has the potential to become one of the most attractive methods in the oil industry to economically unlock hydrocarbon resources. The objective of this paper is to examine the features of subsea fluid-processing technologies and capabilities, and compare the advantages and disadvantages of different facility types. The advantage of subsea processing systems is that they allow fluids to be boosted from longer tieback distances. Constraints associated with subsea processing systems include operation efficiency, produced-waterand sand-handling capabilities, and the system's ability to handle hydrates/scale. In this paper, we reviewed the application of subsea systems in 12 deepwater fields and discussed the significance of each. Furthermore, future subsea-technology development and anticipated challenges are outlined in this paper. The significance of this study is to summarize the lessons learned from current available uses so that future decisions regarding the application of these subsea processing technologies can be made appropriately and efficiently.
The Eagle Ford Shale has emerged as one of the premier unconventional resources in North America. Explosive development has propelled the play to current volumes of 1700 Mbbls/day of oil and 7 bcf/day gas (
A systematic approach and associated findings in implementing optimized recovery methods by the use of multizone (staggered; chevron well pattern configuration) downspacing within the Eagle Ford development area will be presented. The approach will be outlined through the use of numerous datasets including: the review of public production data, published analogue data, decline curve analysis, reservoir modeling, wireline log datasets, buried array microseismic, and geochemical datasets. Current well results, including raw production volumes and rate transient analysis outputs, will be shown to be supporting predicted and modeled results.
This study will bring forward new findings in the effectiveness of current hydraulic fracturing techniques in regards to reservoir drainage limits, expected ultimate field recoveries, and the implications to staggered downspacing. The success of current staggered tests is expected to have a significant impact on future drilling inventory and subsequent asset value, with potential field recoveries being increased by 4 to 7 times current field averages.