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Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality. All three can lead to poor decisions regarding which work to undertake, what issues to focus on, and whether to forge ahead or walk away from a project. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders. Examples are provided including corporate, business unit and department case studies. This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders. Examples are provided including corporate, business unit and department case studies. Safety leadership focuses on the Human Factors (HF) which complement technical training to optimise reliability, safety, compliance, efficiency, and risks within a team-based environment. The IOGP laid down the HF skills and competencies required, and they form the basis for specialised O&G HF training's delivered by Mission Performance. This 1-day course reviews the key human factors but then also reviews what can be done to accelerate and scale operational roll-out for optimum and sustained impact, including integration with existing safety processes and (reporting) systems, refreshers, assessments, measurements, as well as the role of leadership and culture. Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion.
The unconventional revolution in North America has firmly established unconventional resource plays as an integral component of global hydrocarbon production. The established North American resource plays are heterogeneous and vary considerably in terms of play type, stratigraphic organization, and the lithology of the target unit. The Middle East has several world-class source rocks that have charged giant and supergiant conventional fields, which implies many opportunities to develop unconventional resource plays. Within this study, the stratigraphic organization of two prolific source rock intervals within the Early Silurian (Qusaiba Member) and Middle-Late Jurassic (Tuwaiq Mountain Formation and equivalents) is characterized from public-domain data sets. From this, a variety of unconventional plays are conceptualized within these resource intervals.
The systematic classification of established resource plays in North America facilitates analogue identification for these emerging resource intervals across the Middle East. The Montney play is identified as an analogue for the Silurian resource interval and can be used to help validate unproven unconventional play concepts. Within the Jurassic resource interval, multiple analogues are identified that characterize different aspects of the emerging unconventional play types. For instance, stratigraphic architecture within the emerging Tuwaiq Mountain shale play is comparable to the Vaca Muerta play of the Neuquén Basin in South America, while mineralogy is similar to that within the Eagle Ford play and porosity development is akin to the Marcellus play. Applying understanding from these analogues can enable more informed and efficient exploration, appraisal, and development decisions within these frontier and emerging Middle East resource plays.
Exploration in the Middle East can benefit from the creation of sequence stratigraphy-based, scalable, 3D models of the subsurface that are, in effect, a subsurface digital twin that extends from the plate to pore. Stratigraphic and structural organization are integrated into this model to provide a predictive geological framework for analysis of reservoir- and regional-scale geology. This framework enables testing of novel geologic concepts on the Arabian Plate.
The first step of model design is to temporally constrain data within a sequence stratigraphic framework. Publically available data were used in the entire construction of this model. This framework enables the generation of plate-wide chronostratigraphic charts and gross depositional environment (GDE) maps that help to define major changes in the regional geological context. The integration of a geodynamic plate model also provides deeper insight into these spatial and temporal changes in geology. The subsurface model also adopts the principles of Earth systems science to provide insight into the nature of paleoclimate and its potential effect on enhancing the predictive capabilities of the subsurface model. A set of plate-scale regional depth frameworks can be constructed. These, when integrated with GDE maps and other stratigraphic data, facilitate basin screening and play risking.
This plate to play methodology has yielded value through the development of new play concepts and ideas across the Arabian Plate. Exploration has historically relied on the identification of large structures. However, the majority of these are now being exploited. Underexplored stratigraphic traps, and unconventional resources are new concepts that can be better evaluated by using a digital twin of the subsurface. The integration of seismic data and sequence-stratigraphy-calibrated wireline log data can be used to identify the subcrop pattern beneath an unconformity, as well as regions where potential reservoir rocks are in juxtaposition with seals. Intrashelf basins are a key feature of the Arabian Plate. They lead to stratigraphic complexity, yet are key factors for both source rock and reservoir development. From an unconventional perspective, novel, tight plays that exist within or above prominent source rock intervals can also be established.
Value and insight into previously underexplored play concepts, such as within the Silurian Qusaiba Member and the Cretaceous Shilaif Formation of Abu Dhabi, can thus be generated from the stratigraphic attribution of geoscience data. This data can enable better-informed predictions into "white space" away from data control.
Carbonate reservoir rocks of the Najmah formation in Kuwait, with low porosity and low permeability, have been characterized using integrated digital and physical rock analyses methods. High-resolution imaging and analyses determined the microstructural characters of mineral matrix, organic matter (OM) distribution, organic and inorganic pore types, size distribution, and permeability variation within this kerogen-rich Late Jurassic stratigraphic unit.
Considerable heterogeneity of porosity and permeability was observed in the 100-ft studied interval of the Najmah Formation. Two-dimensional scanning electron microscopy (2D-SEM) imaging and three-dimensional focused ion beam SEM (3D-FIB-SEM) imaging highlighted the different types of porosities present within the formation rock. At each depth, several 2D-SEM images were used for characterization and selection of representative locations for extracting 3D FIB-SEM volumes. The 3D volumes were digitally analyzed and volumetric percentages of OM and total porosity were determined. The porosity was further analyzed and quantified as connected, nonconnected, and associated with organic matter. Connected porosity was used to compute absolute permeability in the horizontal and vertical directions in the area of interest.
Porosity associated with OM is an indicator of OM maturity and flow potential. It has been categorized as pendular type, spongy large grain, spongy small grain, fracture porosity within the OM, grain boundary fractures and intergranular porosity covering the entire OM. Permeability is not only influenced by porosity within OM or even apparent transformation ratio (ATR), it is also dependent on pore connectivity, pore sizes, and heterogeneity (e.g., high-permeability streaks). For high porosity samples, almost all pores are connected and contributing to permeability. For low porosity samples with high permeability, the flow is mainly through microfractures. It is possible that intergranular clay pores in highly thermally mature rocks were originally filled with OM and that, during progressive thermal maturation, transformation of OM to hydrocarbon(s) removed much of the pore filling OM.
It has also been observed that, although the total organic carbon (TOC) content of the rocks is significant (up to 18 wt%), and good maturity index (VR0>1), only few examined samples show good connected porosity within the OM. It is essential to evaluate the porosity within the OM thorough high-resolution measurements for pinpointing the prospective layers for future stimulated horizontal wells in this organic-rich source unit. These intervals can be considered as the potential sweet spots after integration with detailed petrophysics and geomechanical parameters for optimized well planning and completion design.
Kang, Jeonggil (Al Dhafra Petroleum Operation Company) | Eriavbe, Francis (Al Dhafra Petroleum Operation Company) | Girinathan, Sajith (Al Dhafra Petroleum Operation Company) | Mohamed, Alyazia (Al Dhafra Petroleum Operation Company) | Doucette, Neil (Al Dhafra Petroleum Operation Company) | Almehsin, Khalil (Al Dhafra Petroleum Operation Company) | Ali Alloghani, Jasim (Al Dhafra Petroleum Operation Company) | Ali Al-Ali, Abdulla (Al Dhafra Petroleum Operation Company) | Ahmed Al Katheeri, Faaeza (Al Dhafra Petroleum Operation Company) | Bhatt, Pranjal (Baker Hughes, a GE Company) | Franquet, Javier (Baker Hughes, a GE Company) | Zhunussova, Gulzira (Baker Hughes, a GE Company) | Uluyuz, Sila (Baker Hughes, a GE Company)
Several challenges are associated with the characterization of organic rich unconventional plays, most significantly with the identification of sweet spots for optimum placement of horizontal wells, estimation of producible hydrocarbons and subsequent stimulation design. This paper presents the petrophysics and geomechanics integration approach from the X Formation and the important factors for the identification of sweet spots.
The case study concentrates on the X Formation that consists of a succession of argillaceous limestone, mostly fine grained packstones and wackestones together with subordinate calcareous shales in the lower part. The complex carbonate lithology and fabric combined with low porosity and the requirement to evaluate total organic carbon presents a challenge to conventional logs and evaluation of them. Amid all the rock properties, the low permeability and productivity dictate the requirement to stimulate the wells effectively. Detailed integration of advanced and conventional log data, core data, mud logs and geomechanical analysis plays a critical role in the evaluation and development of these organic rich unconventional reservoirs. Extensive data gathering was done with wireline logging suite, which covered Resistivitiy/Density/Neutron/Spectral GR- Acoustic logs – Resistivity & Acoustic Images – Dielectric- NMR - Advanced Elemental Spectroscopy technologies and microfrac tests to characterize the hydrocarbon potential, sweet spots and in-situ stress contrast within the organic rich X Formation. The azimuthal and transverse acoustic anisotropies were obtained from X-dipole data to fully characterize the elastic properties of the formation. The static elastic properties were obtained using empirical core correlations as triaxial core tests were not available at the time of the study. The stress profile was calibrated against straddle packer microfrac tests to identify intervals with stress contrast for proper hydraulic fracturing interval selection.
The integration of conventional and advanced logs enabled the accurate evaluation of total organic carbon (TOC), petrophysical volumes, and sweet spot selection. The advanced elemental spectroscopy data provided the mineralogy, amount of carbon presence in the rock, and consequently the associated organic carbon within the X Formation. The NMR reservoir characterization provided lithology independent total porosity. The difference between the NMR and density porosities provides additional information about organic matter. NMR data was utilized in this case study to identify and differentiate the organic matter and hydrocarbon presence within the X Formation.
Acoustic and image logs provided the geomechanical properties that enable selection of the best intervals for microfrac stress measurement and proper fracture containment modeling. Geomechanical workflow allowed identification of intervals with a good stress contrast in X formation. The core data and stress measurements are recommended for the accurate calibration of the stress profiles and hydraulic fracture propagation modeling.
The extensive data integration work presented in this single-well study within X Fomation, is a key factor for any organic rich unconventional reservoir characterization that integrated geology, petrophysics, mineralogy, and geomechanics for sweet spot identification within tight oil carbonate reservoirs.
The unconventional reservoirs (UCRs) play a key role in global oil and gas supply. However, their reservoir characterization is difficult because of complex pore structure and low permeability-viscosity ratio. Usually, traditional techniques hardly can be used for determination of pore structure and estimation of reservoir properties. In this case, digital rock analysis (DRA) shows the potential for capturing detailed pore structure information and simulating rock properties, such as porosity, permeability, electrical properties and elastic properties. Recently, artificial intelligence (AI) techniques have presented an ever-increasing trend in a wide variety of research and commercial fields. Many AI applications can free man from the labor of complicated works in some way. Machine leaning (ML), which is a subdivision of AI, has attracted researchers' attention and been widely used in geoscience and reservoir characterization, such as feature extracting, rock type prediction and reservoir property estimation. The incorporation of AI and DRA is becoming an inevitable development trend for future reservoir study. In this paper, firstly, DRA workflow for reservoir characterization is introduced; secondly, the commonly used ML algorithms in DRA study is reviewed; finally, a case study of characterization of a tight carbonate reservoir with ML algorithm and DRA is presented. The analysis shows that ML can be applied in any part of DRA progress such as image segmentation, feature detection, rock image classification, numerical simulation and result analysis. Compared with traditional DRA algorithm, ML-based methods can reduce manual operation that has greatly impact on the results. The combination of ML and DRA provides a new insight in UCRs characterization and outlook the future opportunities of AI to solve the oilfield problems.
Najmah Formation is a Middle Jurassic tight, fractured formation, spread across many fields in Kuwait. The existing conventional name is Najmah Shale but it could be better called Najmah Mudstone as the unit comprises mainly carbonates with abundant kerogen and bituminous matter.
The entire formation is interesting for its prospectivity and it is cored in different locations in Kuwait in several wells, since its reservoirs are often vertically and laterally heterogeneous due to depositional variability and diagenetic alteration through space and time.
The bituminous intervals, often encountered drilling the Najmah, can induce damaging effects on oil recovery such as reduction of total reservoir porosity, creation of permeability barriers, diminution of water driving efficiency, modification of fluid circulation and rock wettability. Drilling challenges associated with bitumen presence may also arise.
While fundamental questions still remain unclear and controversial, such as how bitumen behaves at in-situ conditions (high stress and high temperature), what shape is bitumen formation, what mechanisms drive bitumen into wellbore, the current consensus is to avoid bitumen intervals as much as possible.
This paper describes how geochemical data allowed for: the characterization of the organics present in the main reservoir, the control of the presence of bitumen and the estimation of its amount in key cored well samples, and the establishment of a methodology to tentatively extend the previous results to non-cored wells.
Both organic and inorganic geochemical investigations were employed, namely Total Organic Carbon (TOC), Pyrolysis analysis, Thermal Desorption Gas Chromatography (TD-GC), X-Ray Fluorescence (XRF), X-Ray Diffraction (XRD).
Pyrolysis analysis can distinguish between free oil (the S1 peak) and heavy organic matter resulting from thermal cracking (the S2 peak), but it cannot differentiate the kerogen from the bitumen, being both included in the S2 peak.
However kerogen is, by definition, insoluble in all organic solvents. This chemophysical property helped in the correct identification and isolation of this range of organic compounds: a long cycle treatment in a Soxhlet extractor using a high-polarity solvent and a low-polarity one guaranteed an efficient extraction of all the soluble components, including the soluble part of bitumen.
The comparative Pyrolysis, i.e. the comparison of the original analysis with the second, post-treatment, analysis revealed the amount of the removed organic matter.
An estimation of bitumen solubility, based on previous analysis on pure bitumen samples, allowed the assessment of total bitumen amount.
An analogous procedure was set up for cuttings samples and its feasibility proved to depend on the type of drilling fluid used while drilling.
This study represents the first integrated characterization of a formation working both as source rock and reservoir rock with the inclusion of comparative Pyrolysis in order to determine the presence of bitumen.
Amer, AimenAi (Schlumberger) | Sajer, Abdulazziz (Kuwait Oil Company) | Al-Adwani, Talal (Kuwait Oil Company) | Salem, Hanan (Kuwait Oil Company) | Abu-Taleb, Reyad (Kuwait Oil Company) | Abu-Guneej, Ali (Kuwait Oil Company) | Yateem, Ali (Kuwait Oil Company) | Chilumuri, Vishnu (Kuwait Oil Company) | Goyal, Palkesh (Schlumberger) | Devkar, Sambhaji (Schlumberger)
Producing unconventional reservoirs characterized by low porosities and permeabilities during early stages of exploration and field appraisal can be challenging, especially in high temperature and high pressure (HPHT) downhole conditions. In such reservoirs, the natural fracture network can play a significant role in flowing hydrocarbons, increasing the importance of encountering such network by the boreholes.
Consequently, the challenge would be to plan wells through these corridors, which is not always easy. To add to the challenge, well design restrictions dictate, the drilling of only vertical and in minor cases deviated wells. This can reduce the possibility of drilling through sub-vertical fracture sets significantly, and once seismic resolution is considered, it may seem that all odds are agents encountering a fracture network.
This article addresses a case where a vertical well is drilled, in the above-mentioned reservoir setting, and missed the natural fracture system. The correct mitigation can make a difference between plugging and abandoning the well or putting it on production.
The technique utilized is based on a borehole acoustic reflection survey (BARS) acquired over a vertical well to give a detailed insight on the fracture network 120 ft away from the borehole. Integrating this technique with core and high-resolution borehole image logs rendered an excellent match, increasing the confidence level in the acoustically predicted fracture corridors.
Based on these findings new perforation intervals and hydraulic stimulation are proposed to optimize well performance. Such application can reverse the well decommissioning process, opening new opportunities for the rejuvenation of older wells.
Dashti, Jalal (Kuwait Oil Company) | Al-Awadi, Mashari (Kuwait Oil Company) | Mushnuri, Sudhakar (Kuwait Oil Company) | Al-Meshilah, Thuwaini (Kuwait Oil Company) | Shoeibi, Ahmad (Geolog International) | Cecconi, Bianca (Geolog International) | Estarabadi, Javad (Geolog International)
Carbon isotopic characterization of mud gas can add great value to the information collected at wellsite and nowadays the interest in this topic is increasing as documented by the study from Poirier et al. (IMOG 2017).
The presented study has the objective of illustrating the data logged through a cavity ring-down spectroscopic (CRDS) technique that allowed collection of robust and reliable carbon isotopic data at wellsite. The logged carbon isotopic data were then used for studying the behavior of two formations (Makhul and Najmah) across different fields. Makhul Formation represents the lower most Formation of Cretaceous in Kuwait, representing predominantly as carbonate rock. In lower Makhul, the high gamma radioactivity is due to enrichment of the shales by uranium. While, Najmah formation is an excellent source rock located in upper Jurassic, it consists of black calcareous limestone source rock with high organic content. Both formations are considered as major source rocks for petroleum systems in state of Kuwait. Many standard interpretation models from the literature were screened and adopted in inter-field correlation, resulting in a good matching with the geographical distribution of the fields.
The second part of the study will focus on the added value of recording carbon isotopic ratios up to C3. The analysis of δ13C3 is demanding from the instrumental point of view, thus, the benefits in terms of formation evaluation that comes from the logging of isotopes up to C3 will be illustrated in the study. With reference to other literatures, δ13C1 readings might be affected by mixing phenomena with biogenic gases, and thus they are not the best candidates to run maturity assessment through isotopes. Instead, carbon isotopic ratios of ethane and propane are not affected by mixing with biogenic gas, resulting in more robust and accurate interpretations. Few models from literature were applied on collected data, allowing choosing the one that matches best the behavior of the studied basin.
Independent measurements on the maturity of the source rock in the area confirmed that the trend highlighted through carbon isotopes logging at wellsite is correct, validating the usefulness of this technique at wellsite.